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UNITED STATES

Form 10-K

(Mark One)

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended Dec. 31, 2002

OR

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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

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

      Northern States Power Co. (a Minnesota corporation), Northern States Power Co. (a Wisconsin corporation), Public Service Co. of Colorado and Southwestern Public Service Co. meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K.

      Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. All outstanding common stock is owned beneficially and of record by Xcel Energy Inc., a Minnesota corporation. Shares outstanding at Feb. 21, 2003:

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      This combined Form 10-K is separately filed by Northern States Power Co., a Minnesota corporation (NSP-Minnesota); Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin); Public Service Co. of Colorado (PSCo); and Southwestern Public Service Co. (SPS). NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are all wholly owned subsidiaries of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the U.S. Securities and Exchange Commission (SEC). Information in this report relating to any individual company is filed by such company on its own behalf. Each registrant makes representation only to itself and makes no representations as to information relating to the other registrants. This report should be read in its entirety.

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Item l.     Business

      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.

      Xcel Energy directly owns six utility subsidiaries that serve electric and natural gas customers in 12 states. Four of these utility subsidiaries are SEC registrants, including 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); and Southwestern Public Service Co., a New Mexico corporation (SPS).

      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 special purpose financing trust.

      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 was incorporated in 1924 under the laws of Colorado. PSCo is an operating utility engaged principally 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; PSR Investments, Inc., which owns and manages permanent life insurance policies on certain employees; Green and Clear Lakes Co., which owns water rights; and PSCo Capital Trust I, a special purpose financing trust. PSCo also holds a controlling interest in several other relatively small 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.

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      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 special purpose financing trust.

Ratemaking Principles

      The utility subsidiaries of Xcel Energy are subject to the regulatory oversight of the Securities and Exchange Commission (SEC) under the PUHCA. As a result, the utility subsidiaries are subject to extensive regulation by the SEC with respect to issuances and sales of securities, acquisitions and sales of certain utility properties and intra-system sales of certain goods and services. In addition, the PUHCA generally limits the ability to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations.

      The Federal Energy Regulatory Commission (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 the utility subsidiaries’ other activities, including regulation of retail rates and environmental matters.

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

      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 electricity 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 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.

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      The PSCW has a biennial base rate-filing requirement. June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the two-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 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.

      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.

Fuel, Purchased Gas and Resource Adjustment Clauses

      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 last 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 last 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 cost recovery mechanism. NSP-Minnesota is required to request a new cost recovery level annually.

      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

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      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, reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

      PSCo currently has seven 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. For certain adjustment mechanisms, 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 fuel and purchased energy costs incurred prior to Dec. 31, 2002. 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 annually to coincide with changes in purchased gas costs. In 2002, PSCo requested to modify the GCA to allow for monthly changes in gas rates. A final decision on this proceeding is expected in 2003. Purchased gas costs and revenues received to recover gas costs are compared on a monthly basis and differences are deferred. 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

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Other Regulatory Mechanisms and Requirements

     NSP-Minnesota

      In December 2000, the NDPSC approved Xcel Energy’s “PLUS” performance-based regulation proposal, effective January 2001, 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. The Company’s performance determines the range of allowed return on equity for its North Dakota electric operations. The plan will generate refunds or surcharges when earnings fall outside of the allowed return on equity range. The PLUS plan will remain in effect through 2005.

     PSCo

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

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

	•	a 10.50 percent return on equity for 2002;
	•	no earnings sharing for 2003;
	•	an annual electric earnings test with the sharing of earnings in excess of the return on equity to be determined in the pending 2002 rate case for 2004 through 2006;

	•	an electric Quality Service Plan (QSP) that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to electric reliability and customer service through 2006;
	•	a gas QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to gas leak repair time and customer service through 2007; and
	•	an ICA that provides for the sharing of energy costs and savings relative to an annual baseline cost per delivered kilowatt-hour. According to the terms of the merger agreement in Colorado, the annual baseline cost was reset in 2002, based on a 2001 test year. The recovery of fuel and purchased energy expense beginning Jan. 1, 2003 will be decided in the 2002 general rate case.

      PSCo regularly monitors and records, as necessary, an estimated customer refund obligation under the earnings test. In April of each year following the measurement period, PSCo files its proposed rate adjustment under the PBRP. The CPUC conducts proceedings to review and approve these rate adjustments annually. During 2002, PSCo filed that its electric department earnings were below the 11 percent return on equity threshold. PSCo has estimated no customer refund obligation for 2002 under the earnings test, the electric QSP or the gas QSP. The 2001 earnings test filing has not been approved. A hearing is scheduled for May 2003.

     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.

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Pending Regulatory Matters

     NSP-Minnesota

      Metro 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 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 Energy, Inc. 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 and the Office of the Attorney General-Residential Utilities Division 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 Minnesota Department of Commerce and Office of the Attorney General 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 bifurcating 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.

      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 customer 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 Department of Commerce has supported deferred accounting to provide for recovery of

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      Electric Transmission Construction — In December 2001, NSP-Minnesota filed for certificates of need authorizing 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 Jan. 30, 2003, the MPUC voted to issue 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. The MPUC has not issued its written order.

      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 early 2004. Construction is expected to be complete in the spring of 2007.

      Merger Agreement — As part of the NCE and NSP merger approval process in Minnesota, NSP-Minnesota agreed to:

	•	reduce its Minnesota electric rates by $10 million annually through 2005;
	•	not increase its electric rates through 2005, except under limited circumstances;
	•	not seek recovery of certain merger costs from customers; and
	•	meet various quality standards.

     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 on 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 to NSP-Wisconsin 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, 2002 order. During its Jan. 31, 2003 meeting, the MPSC considered NSP-Wisconsin’s rehearing request and granted the Company’s request for 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.

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     PSCo

      Merger Agreement — Under the Stipulation and Agreement approved by the CPUC in connection with the Xcel Energy merger, PSCo agreed to:

	•	file a combined electric, gas and steam rate case in 2002 with new rates effective in January 2003;
	•	extend its ICA mechanism through Dec. 31, 2002 with an increase in the ICA base rate from $12.78 per megawatt hour to a rate based on the 2001 actual costs;
	•	continue the electric PBRP and the electric QSP through 2006 with an electric department earnings cap of 10.5 percent return on equity for 2002 and no earnings sharing for 2003;
	•	develop a gas Quality Service Plan for calendar year 2002 through 2007 performance;
	•	reduce electric rates annually by $11 million for the period August 2000 to July 2002; and
	•	cap merger costs associated with electric operations at $30 million and amortize such costs through 2002.

      Incentive Cost Adjustment — PSCo’s 2001 calendar year energy costs under the ICA were approximately $19 per megawatt hour, compared to 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 what was agreed to in the merger stipulation and agreement to mitigate future cost deferrals and to recover the projected ICA energy costs 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, 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 Mar. 31, 2005.

      PSCo’s costs for 2002 were approximately $17 per megawatt hour or approximately $56 million less than the allowed energy recovery rate, which was based on the 2001 test year. Under the ICA mechanism, retail customers and PSCo share this difference equally. A CPUC proceeding to review and approve the incurred and recoverable 2001 costs under the ICA is in process. In 2003, PSCo will file for recovery of its 2002 costs. A review of the 2002 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 seeking to 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 expense recovery revenue of $123 million predicated on calendar year 2003 forecasted sales for PSCo retail. 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 $64 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: (1) a revision in ECA costs caused by a renegotiated purchased power contract; (2) a revised 2003 sales forecast; (3) an updated forecast of natural gas costs used as a fuel source in electric generating stations; and (4) 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. Among other things, the case includes establishing an electric energy recovery mechanism, elimination of the QFCCA, new depreciation rates and recovery of additional plant investment. PSCo

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      Intervenors, including the CPUC Staff and the Colorado Office of Consumer Council (OCC) have filed testimony requesting both electric and gas base rate decreases and increases in fuel and energy revenues that are less than the amounts requested by PSCo. On Feb. 19, 2003, the CPUC postponed the scheduled hearings for 30 days to allow parties to pursue a comprehensive settlement of all issues in this proceeding. New rates are expected to be effective during the second quarter of 2003. A final decision on the recovery of fuel and energy costs will be applied retroactive to Jan. 1, 2003. Until such time, PSCo is billing customers under the IAC, assuming 100 percent pass through cost recovery.

      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 Administrative Law Judge (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 should the CPUC staff file exceptions to the recommended decision, which must be filed by Mar. 3, 2003.

      Gas Rate Reduction — 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.

      2002 Wholesale Sales Data Investigation — In February 2002, after the bankruptcy filing by Enron Corp., the FERC initiated a fact-finding investigation into whether any entity, including Enron, manipulated short-term prices in electric or natural gas markets in the Western United States or otherwise exercised undue influence over wholesale prices in the West since January 2000. PSCo made market-based sales during this period and is included in the FERC investigation.

      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 reparations on behalf of all of PSCo’s gas extension applicants since Oct. 1, 1996, in the amount of $13.6 million, including interest. HBA also seeks recovery of its attorney’s fees.

      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 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.

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

      Texas 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 testimony is being reviewed. Intervenors have proposed that revenues from certain wholesale transactions be credited to Texas retail customers. SPS is opposing this proposed revenue treatment. Hearings are scheduled for March 2003.

      SPS has reported to the PUCT that it has under-collected its fuel costs under the current Texas retail fixed fuel factors. SPS is preparing to file for a fuel cost surcharge.

      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 purchased 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.

      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 by customers under the various fuel clause mechanisms.

      Merger Agreement — As a part of the NCE and NSP merger approval process in Texas, SPS agreed to:

	•	guarantee annual merger savings credits of approximately $4.8 million and amortize merger costs through 2005;
	•	retain the current fuel recovery mechanism to pass along fuel cost savings to retail customers; and
	•	comply with various service quality and reliability standards, covering service installations and upgrades, light replacements, customer service call centers and electric service reliability.

      As a part of the merger approval process in New Mexico, SPS agreed to:

	•	guarantee annual merger savings credits of approximately $780,000 and amortize merger costs through December 2004;
	•	share net non-fuel operating and maintenance savings equally among retail customers and shareholders;

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	•	retain the current fuel recovery mechanism to pass along fuel cost savings to retail customers; and
	•	not pass along any negative rate impacts of the merger.

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 and its utility subsidiaries. Xcel Energy and its utility subsidiaries cannot predict when they will be subject to changes in legislation or regulation, nor can they predict the impacts of such changes on their financial position, results of operation or cash flows. Xcel Energy believes that the prices its utility subsidiaries charge for electricity and the quality and reliability of their service currently place them in a position to compete effectively in the energy market.

      Retail Business Competition — The retail electric business faces some competition as industrial and large commercial customers have some ability to own or operate facilities to generate their own electric energy. 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 faces 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 unbundled wholesale merchant and transmission operations. Xcel Energy’s utility subsidiaries are operating under a joint tariff in compliance with these rules. To date, these provisions have not had a material impact on the operations of Xcel Energy’s utility subsidiaries.

      Utility Industry Changes and Restructuring — The structure of the electric and natural gas utility industry continues to change. Merger and acquisition activity over the past few years has been significant as utilities combine to capture economies of scale or establish a strategic niche in preparing for the future. Some regulated utilities are divesting generation assets. All utilities are required to provide non-discriminatory access to the use of their transmission systems.

      Some states allow retail customers to choose their electricity supplier, and many other states are considering retail access proposals. However, the experience of the state of California in instituting competition, as well as the bankruptcy filing of Enron, have caused delays in industry restructuring.

      The utility subsidiaries cannot predict the outcome of restructuring proceedings in the electric utility jurisdictions they serve at this time. The resolution of these matters may have a significant impact on the financial position, results of operation and cash flows of the utility subsidiaries.

      For more information on the delay of restructuring for SPS in Texas and New Mexico, see Note 10 to the Consolidated Financial Statements.

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

      FERC Investigation of 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

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      Several parties filed requests for rehearing, arguing the November 2001 order was vague and would require the affected utilities to conditionally report future revenues and earnings. 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.

      On May 8, 2002, the FERC ordered all sellers of wholesale electricity and/or ancillary services to the California Independent System Operator or Power Exchange, including Xcel Energy, 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 which may have violated market rules. On May 22, 2002, Xcel Energy 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 reported that at times during 2000 and 2001, its regulated operations 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 Xcel Energy 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 over-schedules due to the volume of records and the relatively small amount of sales.

      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 it 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. The purpose of this non-profit transaction was in consideration of future for-profit transactions. PSCo engaged in these transactions with Reliant for the proper commercial objective of making a profit. It did not enter into these transactions to inflate volumes or revenues and transactions were reported net.

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

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

      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.

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      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 2000, 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.

      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. On Jan. 21, 2003, the Midwest ISO submitted a filing in compliance with the FERC’s December 2002 order, which required certain revisions to the tariff and related agreements. The Midwest ISO has requested that the FERC accept the revised Midwest ISO tariff and agreements to become effective on the day immediately following the consummation of the business combination between the Midwest ISO and the SPP. The Midwest ISO will be required to submit an application to the FERC under Section 203 of the Federal Power Act in order to effectuate the business combination with the SPP.

      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 up to $9 million per year.

      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 applicants are: Alliant Energy’s Iowa company (Interstate Power and Light Co.), Corn Belt Power Cooperative, MidAmerican Energy Co., Nebraska Public Power District, Omaha Public Power District and Xcel Energy, on behalf of its operating utilities. The participants believe TRANSLink is the most cost-effective option available to manage transmission and to comply with regulations issued by the FERC in 1999, known as Order No. 2000, that require investor-owned electric utilities to transfer operational control of their transmission system to an independent 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

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      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 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). The EUC was given six years to perform its research and submit its final report on restructuring, competition, and service territory reforms. 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. The report presented to the legislative council in early 2001 did not include recommendations to change the current tax structure. However, the legislature, without recommendation from the EUC, modified the coal severance and coal conversion taxes primarily to improve the competitive status of

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      TRANSLink — In December 2002, NSP-Minnesota filed for MPUC approval to transfer functional control of the Company’s 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.

     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, and should encourage the development of merchant plants by making sales from independent power producers more competitive. Additional legislation was passed that enables regulated utilities to enter into leased generation contracts with unregulated generation affiliates. The new legislation provides utilities a new financing mechanism and option to meet their customers’ energy needs. In 2002, the PSCW approved the first power plant proposal utilizing the new leased generation contract arrangement. While industry-restructuring changes continue in Wisconsin, the movement towards retail customer choice has virtually 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 and 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, none of the 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 the Company’s 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. A similar filing is not 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 incurred to prepare for customer choice in New Mexico of approximately $5.1 million. 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

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      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. The stipulation provides for the recovery of $5.9 million through an incremental cost recovery rider and the capitalization of $1.9 million for metering equipment. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million in the first quarter of 2002. Recovery of the $5.9 million began in July 2002.

      For more information on restructuring in Texas and New Mexico, see Note 10 to the Consolidated Financial Statements.

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

      Oklahoma Restructuring — The Electric Restructuring Act of 1997 was enacted in Oklahoma during 1997. This legislation directed a series of studies to define the orderly transition to consumer choice of electric energy supplier by July 1, 2002. 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.

      TRANSLink — In November and December 2002, SPS filed for PUCT and NMPRC approval to transfer functional control of the Company’s electric transmission system to 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.

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

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     Purchased Power

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

      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 overall electricity use, 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:

	•	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 plant and at the Monticello plant 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 issues of spent nuclear fuel storage limitations and their effect on the future of nuclear generation in Minnesota in the 2003 legislative session.

      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 2002-2005 time period.

      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 (retail and wholesale

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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

      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 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.

      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

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      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 generating 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.

      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 market agreements.

Trading Operations

      Xcel Energy’s utility subsidiaries conduct various trading operations, including the purchase and sale of electric energy. Participation in short-term wholesale energy markets provides market intelligence and information that supports the energy management of each utility subsidiary. Xcel Energy’s utility subsidiaries reduce commodity price and credit risks by using physical and financial instruments, to minimize commodity

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Nuclear Power Operations and Waste Disposal

      NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are licensed to operate until 2013 and 2014, respectively.

      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 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 life, if off-site low-level disposal facilities were not available to NSP-Minnesota.

      High-Level 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 14 to the Consolidated Financial Statements for further discussion of this matter.

      NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants. NSP-Minnesota has expanded the used nuclear fuel storage facilities at its Monticello plant by replacement of the racks in the storage pool and by shipping 1,058 used fuel assemblies to a General Electric storage facility. The Monticello plant is expected to have sufficient pool storage capacity to the end of its current operating license in 2010.

      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 national temporary storage site for spent nuclear fuel. The PFS will undertake the development, licensing, construction and operation of a storage facility on the Skull Valley Indian Reservation in Utah. The

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      If the Prairie Island plant is to continue operating, 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.

      Based on analysis of the options, NSP-Minnesota believes the most reliable, lowest cost, environmentally sound way to provide the needed 1,700 megawatts of energy is to continue to operate the nuclear power plants at Prairie Island and Monticello.

      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 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 has issued a number of regulations, bulletins and orders that require analyses, modification and additional equipment at commercial nuclear power plants. 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.

      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 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.

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      For further discussion of nuclear issues, see Notes 13 and 14 to the Consolidated Financial Statements.

Electric Operating Statistics (NSP-Minnesota)

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Electric Operating Statistics (NSP-Wisconsin)

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Electric Operating Statistics (PSCo)

(1)	2001 and 2000 customers include 18,000 individual customers that subsequently became two incorporated municipalities in 2002.

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Electric Operating Statistics (SPS)

(1)	Other electric revenues is negative in 2000 primarily due to an increased provision for rate refunds.

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.

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      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 LDC’s, 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 LDC’s 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 (customers with an alternate energy supply). The maximum daily send out (firm and interruptible) for the combined system of NSP-Minnesota and NSP-Wisconsin was 650,641 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 640,000 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 exchange one form of demand for another. In October 2001, the MPUC approved NSP’s 2000-2001 entitlement levels, which allow NSP-Minnesota to recover the demand entitlement costs associated with the increase in transportation and storage levels in its monthly PGA. NSP-Minnesota’s 2001-2002 entitlement levels were approved on April 3, 2002. 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

      PSCo projects peak day gas supply requirements for firm sales and backup transportation (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 is 2,206,870 MMBtu per day. The maximum daily delivery for 2002 (firm and interruptible services) was 1,652,459 MMBtu on Feb. 25, 2002.

      PSCo purchases 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

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