Back to GetFilings.com

Table of Contents

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, 2001

OR

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

For the transition period from                     to                     

      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

      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 March 15, 2002:

Table of Contents

INDEX

1

Table of Contents

      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 on 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.

2

Table of Contents

Item 1.     Business

COMPANY OVERVIEW

      On Aug. 18, 2000, New Century Energies, Inc. (NCE) and Northern States Power Co. (NSP) merged and formed Xcel Energy Inc. (Xcel Energy). Xcel Energy, a Minnesota corporation, is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). As part of the merger, NSP transferred its existing utility operations that were being conducted directly by NSP at the parent company level to a newly formed subsidiary of Xcel Energy named Northern States Power Co.

      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

      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 0.4 million 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

      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 229,000 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 in Wisconsin and Michigan.

      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 hold real estate.

     PSCo

      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 1.1 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; PS Colorado Credit Corp., a finance company that financed certain of PSCo’s current assets, but was dissolved in 2002; and PSCo Capital Trust I, a special purpose financing trust. PSCo also holds a controlling interest in several other relatively small ditch and water companies whose capital requirements are not significant.

3

Table of Contents

     SPS

      SPS was incorporated in 1921 under the laws of New Mexico. SPS is an operating utility engaged primarily in the generation, transmission, distribution and sale of electricity, which serves approximately 387,000 electric customers in portions of Texas, New Mexico, Oklahoma and Kansas. The wholesale customers served by SPS comprise approximately 34 percent of the total kilowatt-hour sales.

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

UTILITY REGULATION

Ratemaking Principles

      The utility subsidiaries of Xcel Energy are subject to the jurisdiction of the Securities and Exchange Commission (SEC) under the PUHCA. As a result, the utility subsidiaries are subject to extensive regulations 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 and wholesale electric energy sold in interstate commerce, hydro facility licensing and certain other activities of Xcel Energy’s utility subsidiaries. Federal, state and local agencies also have jurisdiction over many of Xcel Energy’s other activities.

      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 strive to comply with all rules and regulations issued by the various agencies.

     NSP-Minnesota

      Retail rates, services and other aspects of NSP-Minnesota’s operations are subject to the jurisdiction of the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC) and the South Dakota Public Utilities Commission (SDPUC) within their respective states. The MPUC also 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 has received authorization from the FERC to act as a power marketer.

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

     NSP-Wisconsin

      NSP-Wisconsin is subject to regulation of similar scope by the Public Service Commission of Wisconsin (PSCW) and the Michigan Public Service Commission (MPSC). In addition, each of the state commissions certifies the need for new generating plants and electric and retail gas transmission lines of designated capacities to be located within the respective states before the facilities may be sited and built.

      The PSCW has a biennial filing requirement. By 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 effective with the start of the test year.

4

Table of Contents

     PSCo

      PSCo is subject to the jurisdiction of the Colorado Public Utility 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 and accounting practices and policies. PSCo has received authorization from the FERC to act as a power marketer. Also, PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.

     SPS

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

Fuel, Purchased Gas and Resource Adjustment Clauses

     NSP-Minnesota

      NSP-Minnesota’s retail electric rate schedules provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy. NSP-Minnesota is permitted to recover financial instrument costs through a fuel clause adjustment, a mechanism that allows NSP-Minnesota to bill customers for the actual cost of fuel used to generate electricity at its plants and energy purchased from other suppliers. 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.

      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). These costs are recovered through an annual recovery mechanism for electric and gas conservation and energy management program expenditures. NSP-Minnesota is required to request a new cost recovery level annually.

     NSP-Wisconsin

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

      NSP-Wisconsin has a gas cost recovery mechanism 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

5

Table of Contents

     PSCo

      PSCo has five adjustment clauses: the incentive cost adjustment (ICA), the gas cost adjustment (GCA), the steam cost adjustment (SCA), the demand side management cost adjustment (DSMCA) and the qualifying facilities capacity cost adjustment (QFCCA). These adjustment clauses allow certain costs to be passed through to retail customers. PSCo is required to file applications with the CPUC for approval of adjustment mechanisms in advance of the proposed effective dates.

      The ICA allows for an equal sharing between customers and shareholders of certain fuel and energy cost increases. PSCo, through its GCA, is allowed to recover its actual costs of purchased gas. The GCA rate is revised annually to coincide with changes in purchased gas costs. Purchased gas costs and revenues received to recover gas costs are compared on a monthly basis and differences are deferred. 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 rates. The SCA rate is revised annually to coincide with changes in fuel costs. The QFCCA provides for recovery of purchased capacity costs from certain QF projects not otherwise reflected in base electric rates.

      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.

     SPS

      Fuel and purchased power costs are recoverable in Texas through a fixed fuel factor, which is part of SPS’ 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 under/over-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. On December 17, 2001, SPS filed an application with the NMPRC for authorization to replace its fixed annual fuel factor with a monthly fuel factor. In January 2002, the NMPRC authorized SPS to implement a monthly adjustment factor on an interim basis beginning with the February 2002 billing cycle.

Other Regulatory Mechanisms and Requirements

     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;

6

Table of Contents

	•	an annual electric earnings test with the sharing of earnings in excess of the return on equity set in the 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 rate agreement in Colorado, the annual baseline cost will be reset in 2002, based on a 2001 test year.

      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. PSCo has estimated no customer refund obligation for 2001 under the earnings test. In November 2000, the CPUC ruled on the unresolved issues related to the 1998 earnings test that will result in the reduction of customer rates by $5.1 million effective January 2001.

      During 2001, PSCo settled all unresolved issues related to the 1999 and 2000 QSP electric reliability performance measure. An accrual for related customer refunds of $8.2 million was recorded and paid in 2001. PSCo has recorded an estimated customer refund obligation for the 2001 QSP electric reliability performance measure of approximately $4.2 million.

     SPS

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

Pending Regulatory Matters

     NSP-Minnesota

      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. The projected cost is approximately $130 million. The proposal is now in hearings before an administrative law judge. The MPUC must issue a decision before the end of 2002.

      North Dakota Rate Case — In October 2000, NSP-Minnesota filed a request with the NDPSC to increase natural gas rates by approximately 3.3 percent, or $1.4 million, annually. In June 2001, the NDPSC approved an increase of approximately $860,000 annually, effective July 13, 2001.

      Merger Rate 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;

7

Table of Contents

	•	not seek recovery of certain merger costs from customers; and
	•	meet various quality standards.

     NSP-Wisconsin

      NSP-Wisconsin Electric Power Supply Rate Request — In May 2001, NSP-Wisconsin filed an application with the PSCW requesting an increase in Wisconsin retail electric rates due to significant increases in power supply costs. This increase was necessary to recover increases in fuel and purchased power costs from wholesale suppliers who charge market-based prices. On June 28, 2001, the PSCW approved an interim fuel cost surcharge of $0.00374 per kilowatt-hour. On Oct. 18, 2001, the PSCW issued a final order in the docket that replaced the interim surcharge with a $0.00382 per kilowatt-hour increase in base electric rates. The combination of the interim fuel surcharge and the base rate increase increased NSP-Wisconsin’s electric revenue by approximately $5.6 million over the last six months of 2001.

      NSP-Wisconsin General Rate Case — On June 1, 2001, NSP-Wisconsin filed its required biennial rate application with the PSCW requesting no change in Wisconsin retail electric and gas base rates. NSP-Wisconsin requested the PSCW approve its application without hearing, pending completion of the Staff’s audit. The PSCW issued a final order on Dec. 7, 2001 approving NSP-Wisconsin’s application without hearing. As a result, base rates in effect as of the end of 2001 will stay in effect through the 2002 - 2003 biennium.

     PSCo

      2002 General Rate Case — In May 2002, PSCo is expected to file a general retail electric, gas and thermal energy base rate case with the CPUC. This filing is required as part of the Xcel Energy merger Stipulation and Agreement approved by the CPUC. The case will include setting the electric energy recovery mechanism, elimination of the QFCCA, new depreciation rates and recovery of additional plant investment. The resulting change in rates is expected to be effective Jan. 1, 2003.

      2000 Gas Rate Case — In July 2000, PSCo filed a retail rate case with the CPUC requesting an annual increase in its gas revenues of approximately $40 million. The request for a rate increase reflects revenues for additional plant investment, a 12.5 percent return on equity, new depreciation rates and recovery of the dismantlement costs associated with the Leyden Gas Storage facility. In February 2001, the CPUC granted an increase in gas revenues of $14.2 million and authorized an 11.25 percent return on equity. The CPUC did not grant the new depreciation rates proposed by PSCo, but rather granted new depreciation rates proposed by the CPUC staff. The CPUC denied recovery of the dismantlement costs associated with the Leyden Gas Storage facility in this case since such costs had not yet been incurred and recommended PSCo request recovery in a later rate filing.

      Pacific Northwest Power Market — A complaint has been filed at the FERC requesting that the agency set for investigation, pursuant to Section 206 of the Federal Power Act, the justness and reasonableness of the rates of wholesale sellers in the spot markets in the Pacific Northwest, including PSCo. The FERC decided to hold a preliminary evidentiary hearing to facilitate development of a factual record on whether there may have been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for the period beginning Dec. 25, 2000 through June 20, 2001. Such hearing was held before an administrative law judge of the FERC in August 2001. The administrative law judge recommended that the FERC conclude that the rates charged were not unjust and unreasonable, and accordingly, that there should be no refunds. PSCo believes that the findings should be upheld at the FERC. However, the matter is still pending before the FERC, and the ultimate outcome cannot be determined.

      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 West 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.

8

Table of Contents

      Merger Rate Agreement — As a part of the NCE and NSP merger approval process in Colorado, PSCo agreed to:

	•	reduce its retail electric rates by an annual rate of $11 million for the period of August 2000 through July 2002;
	•	file a combined electric and natural gas rate case in 2002, with new rates effective January 2003;
	•	cap merger costs associated with the electric operations at $30 million and amortize the merger costs for ratemaking purposes through 2002;
	•	continue the electric PBRP and the QSP currently in effect through 2006, with modifications to cap electric earnings at a 10.5 percent return on equity for 2002, to reflect no earnings sharing in 2003 since new base rates would have recently been established, and to increase potential bill credits if quality standards are not met; and
	•	develop a QSP for the natural gas operations to be effective for calendar years 2002 through 2007.

     SPS

      Fuel Recovery — At least every three years, SPS is required to file an application for the PUCT to retrospectively review the operations of a utility’s electric generation and fuel management activities. In June 2000, 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 $419 million, for the period from January 1998 through December 1999. SPS was granted full recovery of these costs by the PUCT in March 2001.

      SPS Texas Retail Fuel Factor and Fuel Surcharge Application — SPS has filed an application with the PUCT to increase its fixed fuel factor and to surcharge past fuel cost under-recoveries of approximately $47 million for the months October 2000 through January 2001. Hearings were held in May 2001. In October 2001, the PUCT issued a final decision granting SPS’ request to account for wholesale firm sales through the base ratemaking process and to continue its practice of revenue crediting margins from off-system sales, or wholesale non-firm sales. Furthermore, SPS’ request to revise its voltage level fuel factors was granted.

      In May 2001, SPS filed an application with the PUCT seeking authority to surcharge approximately $27 million in additional fuel under-recoveries and related interest accrued during February and March 2001. In July 2001, SPS filed a motion to abate the proceeding until September 2001 since the market price of natural gas unexpectedly and significantly decreased. In September 2001, SPS determined that its cumulative fuel under-collections were below the PUCT materiality threshold. As a result of this determination, SPS withdrew its application and moved to dismiss this proceeding. The PUCT dismissed this proceeding in September 2001.

      In November 2001, SPS filed a motion with the PUCT requesting the termination of all currently approved surcharges in December 2001. SPS made this request to prevent any over-collection of historical under-recoveries due to the rapid and unforeseen decreases in the price of natural gas. This request was granted by the PUCT.

      In December 2001, SPS submitted an application seeking authority to immediately revise its fixed fuel factors on an interim basis to prevent any over-collection of historical under-recoveries due to the rapid and unforeseen decreases in the price of natural gas. SPS also requested that it be allowed to file a supplemental application to revise its fixed fuel factors. On Dec. 19, 2001, the Administrative Law Judge issued an order approving the interim fixed fuel factors and SPS’ request to file a supplemental application. SPS’ supplemental application was filed in February 2001 and on March 25, 2002, a unanimous stipulation was filed to reduce SPS’ fixed fuel factor to reflect projected lower fuel costs for running the SPS’ power plants.

      SPS Texas Transition to Competition Cost Recovery Application — In December 2001, SPS filed an application with the PUCT to recover $20.3 million in costs from the Texas retail customers associated with the transition to competition. The filing was amended in March 2002 to reduce the recoverable costs by

9

Table of Contents

      SPS New Mexico Fuel Factor — In October 2000, SPS filed an unopposed motion with the NMPRC, seeking to change the date for the implementation of its next fixed annual fuel factor. SPS was approximately $12.8 million under-collected in fuel and purchased power costs through August 2000 and projected that these under-collections would continue based on recent increases in natural gas costs. In October 2000, the NMPRC approved SPS’ revised fixed annual fuel factor to be effective in the November 2000 billing cycle. In March 2001, SPS filed an unopposed motion with the NMPRC, seeking to change the date for the implementation of its next fixed annual fuel factor. SPS was estimating that it would be $33 million under-collected in fuel and purchased power costs through March 2001 and projected that these under-collections would continue based on recent increases in natural gas costs. In March 2001, the NMPRC approved SPS’ revised fixed annual fuel factor to be effective in the April 2001 billing cycle.

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

      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.

      Merger Rate Agreements — 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 nonfuel operating and maintenance savings equally among retail customers and shareholders;
	•	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.

10

Table of Contents

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 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 operations and cash flows of Xcel Energy. 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 operations 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 increasing 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 environment. While each of Xcel Energy’s utility subsidiaries face these challenges, these subsidiaries believe their rates are competitive with currently available alternatives. Xcel Energy’s utility subsidiaries are taking actions to lower operating costs and are working with their customers to analyze energy efficiency, load management and cogeneration 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 increasing competition in the supply of bulk power, due to federal and state initiatives to provide open access to utility transmission systems. Under current FERC rules, utilities are required to provide wholesale open-access transmission services and to unbundle wholesale merchant and transmission 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 nondiscriminatory access to the use of their transmission systems.

      Some states have begun to 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.

      Major issues that must be addressed include mitigating market power, divestiture of generation capacity, transmission constraints, legal separation, refinancing of securities, modification of mortgage indentures, implementation of procedures to govern affiliate transactions, investments in information technology and the pricing of unbundled services, all of which have significant financial implications. Xcel Energy cannot predict the outcome of restructuring proceedings in the electric utility jurisdictions it serves at this time. The resolution of these matters may have a significant impact on the financial position, results of operations and cash flows of Xcel Energy. For more information on the delay of restructuring for SPS in Texas and New Mexico, see Note 10 to the Financial Statements under Item 8.

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

      Section 206 Investigation Against All Wholesale Electric Sellers — In November 2001, the FERC issued an order under Section 206 of the Federal Power Act initiating a “generic” investigation proceeding against all jurisdictional electric suppliers making sales in interstate commerce at market based rates. NSP-Minnesota, PSCo and SPS had previously received FERC authorization to make wholesale sales at market based rates,

11

Table of Contents

      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. The FERC is expected to rule in this matter in 2002.

      Midwest ISO Begins 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 U.S., 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 kV and above) transmission systems to the Midwest ISO when the Midwest ISO is fully operational, expected later in 2002. The Midwest ISO will then control the operations of these facilities and the facilities of neighboring electric utilities.

      In October 2001, the FERC issued an order in the separate proceeding to establish the initial Midwest ISO regional transmission tariff rates, ruling that all transmission services (with limited exceptions) in the Midwest ISO region must be subject to the Midwest ISO regional tariff and administrative surcharges to prevent discrimination between wholesale transmission service users. The FERC order unilaterally modified the agreement with the Midwest ISO signed in August 2000. The FERC order is expected to increase wholesale transmission costs to NSP-Minnesota and NSP-Wisconsin by up to $8 million per year prospectively.

      TRANSLink Transmission Company LLC — In September 2001, the Xcel Energy operating companies joined a proposal with several other electric utilities in the U.S. Mid-continent region to form TRANSLink Transmission Company LLC (TRANSLink), an independent transmission company (ITC) which would own and/or operate electric high voltage transmission facilities within a FERC-approved regional transmission organization (RTO). Initially, the applicants propose that the high voltage transmission systems of NSP-Minnesota and NSP-Wisconsin be under the functional control of TRANSLink under an operating agreement between the utilities and TRANSLink, which would then be a member of the Midwest ISO RTO. The electric transmission facilities of SPS and PSCo would also be operated by TRANSLink, but would not initially be part of an RTO because no FERC-approved RTO is operational in the southwestern or western United States at this time.

      TRANSLink would pay the Xcel Energy operating companies a fee for use of their transmission systems, determined on a regulated cost of service basis, and would collect its administrative costs through transmission rate surcharges. The TRANSLink participants argue that RTO participation through the TRANSLink ITC would comply with FERC Order 2000 at a lower cost than RTO participation as vertically integrated utilities. The TRANSLink proposal is now pending FERC approval. Several state approvals would also be required to implement the proposal. Subject to receipt of required regulatory approvals, TRANSLink could be operational by year-end 2002.

      Supreme Court Decision on Appeals of FERC Order No. 888 — On March 4, 2001, the U.S. Supreme Court upheld the FERC’s rulings on Order No. 888 dealing with federal jurisdiction over retail transmission service. The court rejected appeals by nine states, lead by New York, which argued that the FERC had gone too far in asserting jurisdiction over unbundled retail transmission, and by Enron, which argued that the FERC should have asserted jurisdiction over all transmission, including bundled retail transmission service. The court ruled the FERC has broad authority over all transmission service in interstate commerce and wholesale sales in interstate commerce.

12

Table of Contents

      Standards of Conduct Rulemaking — In October 2001, the FERC issued proposed rules which would substantially increase the “functional separation” requirements under existing FERC rules (Orders No. 497 and 889) between the regulated electric and natural gas transmission functions of the Xcel Energy operating companies and Viking Gas, and the wholesale electric and natural gas marketing functions of PSCo, NSP-Minnesota, NRG and e prime. The proposed rules, if adopted, would require substantially increased functional separation, causing a loss of integration efficiencies and thus higher costs. In December 2001, Xcel Energy and numerous other parties filed comments opposing the proposed rules. FERC is expected to act in the rulemaking in 2002.

      Standard Market Design Changes Planned — The FERC has initiated a rulemaking proceeding into modifications to the “wholesale market design” adopted when the FERC ordered all jurisdictional electric utilities to begin providing open access electric transmission service in 1996 with Order No. 888. The FERC is expected to adopt new standard market design rules through a notice and comment rulemaking proceeding later in 2002. The new market design rules, if adopted, are expected to materially impact future wholesale electric sales and transmission services (and perhaps revenues) for the Xcel Energy utility subsidiaries and RTOs.

     NSP-Minnesota

      Minnesota Restructuring — In 2001, the Legislature passed an energy security bill that includes provisions that are intended to streamline the siting process of new generation and transmission facilities. It also includes voluntary benchmarks for achieving renewable energy as a portion of the utility supply portfolio. There is unlikely to be any further action on restructuring in 2002. Although the Minnesota Chamber still supports restructuring, leaders have indicated a “let’s go slow” approach to restructuring given the California experience.

      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, overhauled the application of the coal severance and coal conversion taxes primarily to improve the competitive status of North Dakota lignite for generation. During 2002, the committee continued its review and will present legislation to the legislative assembly in January 2003.

      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. Impacts of the plan on 2001 business will be reported to the NDPSC in the second quarter of 2002. The PLUS Plan will remain in effect through 2005.

     NSP-Wisconsin

      Wisconsin Restructuring — The state of Wisconsin continued its incremental approach to industry restructuring by passing 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. However, while industry-restructuring changes continue in Wisconsin, the movement towards retail customer choice has slowed considerably.

13

Table of Contents

      Michigan Restructuring — In June 2000, Michigan’s “Customer Choice and Electricity Reliability Act,” became law. This law required NSP-Wisconsin to provide its Michigan customers the opportunity to select an alternative electric energy supplier, beginning on Jan. 1, 2002. NSP-Wisconsin successfully implemented internal procedures, and obtained Michigan Public Service Commission (MPSC) approval for these procedures, in order to meet the Jan. 1, 2002 deadline. Key elements of the internal procedures include the development of retail open access tariffs, unbundled billing for all Michigan customers, and release of environmental and fuel disclosure information through a bill insert. Outstanding issues to be addressed by the MPSC include finalizing “anti-slamming/anti-cramming” consumer protection provisions, approving code of conduct compliance plans, and formalizing distribution reliability and performance standards. To date, none of NSP-Wisconsin’s retail electric customers have converted to a competing supplier.

     PSCo

      Colorado Restructuring — During 1998, a bill was passed in Colorado that established an advisory panel to conduct an evaluation of electric industry restructuring and customer choice. During 1999, this panel concluded that Colorado would not significantly benefit from opening its markets to retail competition. There was no legislative action with respect to restructuring in Colorado during the 2000 or 2001 legislative sessions and none is anticipated during 2002.

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. SPS has 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 regulatory recovery of these costs through a rate rider in the next New Mexico rate case filed.

      Texas Restructuring — In June 2001, the Governor of Texas signed legislation postponing the deregulation and restructuring of SPS until 2007. This legislation amended the 1999 legislation, Senate Bill No. 7 (SB-7), which provided for retail electric competition beginning January 2002. Under the newly-adopted legislation, prior PUCT orders issued in connection with the restructuring of SPS will be considered null and void. SPS’ restructuring and rate unbundling proceedings in Texas have been terminated. In addition, under the new legislation, SPS is entitled to recover all reasonable and necessary expenditures made or incurred before Sept. 1, 2001, to comply with SB-7. SPS has filed an application with the PUCT, requesting a rate rider to recover these costs incurred preparing for customer choice of approximately $20.3 million.

      For more information on restructuring in Texas and New Mexico, see Note 10 to the Financial Statements under Item 8.

      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 was signed into law to formally delay electric restructuring until restructuring issues could be studied further and new enabling legislation could be enacted. Senate Bill 440 established the Electric Restructuring Advisory Committee and directed the committee to complete an interim report on the state’s transmission infrastructure needs by Dec. 31, 2001. The Advisory Committee submitted this report to the Governor and Legislature on Dec. 31, 2001.

Capacity and Demand

      Assuming normal weather during 2002, 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 2002 are listed below.

14

Table of Contents

      The peak demand for the NSP System, PSCo and SPS all typically occurs in the summer. The 2001 system peak demand for the NSP System occurred on Aug. 6, 2001. The 2001 system peak demand for PSCo occurred on July 30, 2001. The 2001 system peak demand for SPS occurred on July 26, 2001.

Energy Sources

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

     Purchased Power

      Xcel Energy’s electric utility subsidiaries have contractual arrangements to purchase power from other utilities and nonregulated energy suppliers. Capacity, typically measured in kilowatts or megawatts, is the measure of the rate at which a particular generating source produces electricity. Energy, typically measured in kilowatt-hours or megawatt-hours, is a measure of the amount of electricity produced from a particular generating source over a period of time. Purchase power contracts typically provide for a charge for 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 is 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 August 2001, the MPUC approved with modifications to NSP-Minnesota’s Resource Plan for 2000 to 2015. The plan described how Xcel Energy intends to meet the energy needs of the NSP System. The plan contained 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 operation of existing resources. In summary, the plan, which the MPUC approved:

	•	forecasts 1.6 percent annual growth in the NSP System’s energy and peak demand requirements;
	•	outlines NSP System’s demand side management and conservation programs;
	•	shows new capacity needs of up to 600 megawatts by 2005 and 4,200 megawatts by 2015;
	•	describes how NSP-Minnesota will achieve the mandated renewable energy sources of 425 megawatts of wind and 125 megawatts of biomass by 2002, which have now been met; and
	•	updates the status of spent nuclear fuel at the Prairie Island plant and describes how it can continue to operate through the end of its license given different alternatives for storing spent nuclear fuel.

15

Table of Contents

      The resource plan proposes to satisfy the NSP System resource needs through the following energy source options:

	•	continued use of existing generation facilities, including the repowering of Black Dog Units 1 and 2;
	•	demand reduction of an additional 1,174 megawatts by 2015 through conservation and load management;
	•	acquisition of competitively priced resources through competitive bidding;
	•	seek offers to replace Prairie Island through competitive bidding where the offers must have a cancellation option if Xcel Energy resolves Prairie Island’s waste storage issues.

     PSCo Resource Plan

      PSCo estimates it will purchase approximately 28 percent of its total electric system energy input for 2002. Approximately 45 percent of the total system capacity for the summer 2002 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.

     Purchased Transmission Services

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

Fuel Supply and Costs

      The following tables present the delivered cost per million British thermal unit (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

16

Table of Contents

     NSP-Minnesota and NSP-Wisconsin

      NSP-Minnesota and NSP-Wisconsin normally maintain between 30 and 45 days of coal inventory at each plant site. Estimated coal requirements at NSP-Minnesota’s major coal-fired generating plants are approximately 12 million tons per year. NSP-Minnesota and NSP-Wisconsin have long-term contracts providing for the delivery of up to 100 percent of 2002 coal requirements and up to 85 percent of their 2003 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 2002 will have a sulfur content of less than 1 percent. NSP-Minnesota and NSP-Wisconsin have contracts for a maximum of 22 million tons of low-sulfur coal for the next two years. The contracts are with two Montana coal suppliers and three Wyoming suppliers with expiration dates ranging between 2002 and 2005. NSP-Minnesota and NSP-Wisconsin could purchase approximately 7 percent of their coal requirements in the spot market in 2002 and 35 percent of coal requirements in 2003 if spot prices are more favorable than contracted prices.

      NSP-Minnesota and NSP-Wisconsin’s current fuel oil inventory is adequate and they have access to additional spot purchase supplies to meet anticipated 2002 requirements. Additional oil may be obtained through spot purchases.

      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 85 percent of uranium, conversion and enrichment requirements through the year 2005. These contracts expire at varying times between 2002 and 2006. The overlapping nature of contract commitments will allow NSP-Minnesota to maintain 50 percent to 100 percent coverage beyond 2002. NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Fuel fabrication is 100 percent committed through 2004 and 30 percent committed through 2010.

     PSCo

      PSCo’s primary fuel for its steam electric generating stations is low-sulfur western coal. PSCo’s coal requirements are purchased primarily under long-term contracts with suppliers operating in Colorado and Wyoming. During 2001, PSCo’s coal requirements for existing plants were approximately 10.5 million tons, a substantial portion of which was supplied pursuant to long-term supply contracts. Coal supply inventories at Dec. 31, 2001, were approximately 36 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 under 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 2002. Any remaining requirements may be purchased from this contract or the spot market. PSCo has contracted for coal supplies to supply approximately 95 percent of the Cherokee and Valmont Stations’ projected requirements in 2002.

      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

17

Table of Contents

      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

      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, 2001, coal inventories at the Harrington and Tolk sites were approximately 41 and 49 days supply, respectively. TUCO has a long-term coal supply agreement to supply approximately 98 percent of Harrington’s projected requirements in 2002. 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 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 57 percent of SPS’ gas requirements during 2001 were purchased under spot agreements.

Trading Operations

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

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 and are licensed to operate until 2013 and 2014, respectively.

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

      Federal law places responsibility on each state for disposal of its low-level radioactive waste. Low-level radioactive waste 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 waste), and the Clive facility, located in Utah (class A low-level waste 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 waste 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 waste proces-

18

Table of Contents

      The federal government has the responsibility to dispose of, or permanently store, domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the Department of Energy (DOE) to implement a program for nuclear waste 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 wastes at a permanent storage or disposal facility by 1998. None of NSP-Minnesota’s spent nuclear fuel has yet been accepted by the DOE for disposal. See Item 3 — Legal Proceedings and Note 14 to the Financial Statements under Item 8 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 spent fuel pool has undergone two storage rack replacements. The on-site storage pool for spent nuclear fuel at Prairie Island was nearly filled and adequate space was no longer available. In 1994, a Minnesota law was enacted authorizing NSP-Minnesota to install 17 spent fuel casks for storage of spent nuclear fuel at Prairie Island. NSP-Minnesota has determined 17 casks will allow facility operation until 2007. As of Dec. 31, 2001, 14 storage casks were loaded and stored on the Prairie Island nuclear generating plant site. The Minnesota Legislature established several energy resource requirements and other commitments for NSP-Minnesota to obtain the Prairie Island temporary nuclear fuel storage facility approval. NSP-Minnesota has implemented programs to meet the legislative commitments.

      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 Nuclear Regulatory Commission (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 NRC license review process consists of formal evidentiary hearings and opportunity for public input. Storage cask certification efforts are continuing, with one cask vendor on track to meet the project goals. The interim used fuel storage facility could be operational and able to accept the first shipment of spent nuclear fuel by 2004. However, due to uncertainty regarding regulatory and governmental approvals, it is possible that this interim storage may be delayed or not available at all.

      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 28-year-old 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.

     Nuclear Management Company (NMC)

      During 1999, NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin Public Service Corp. and Alliant Energy established the NMC. Consumers Power joined the NMC during 2000, and transferred operating authority for the Palisades nuclear plant to the NMC in 2001. The five affiliated companies own eight nuclear units on six sites, with total generation capacity exceeding 4,500 megawatts. Xcel Energy is currently a 20 percent owner of the NMC.

19

Table of Contents

      The NRC has approved requests by NMC’s affiliated utilities to transfer operating authority for their nuclear plants to the NMC, formally establishing the NMC as an operating company. The NMC manages the operations and maintenance at the plants, and is responsible for physical security. The NMC 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.

      For further discussion of nuclear issues, see Note 13 and Note 14 to the Financial Statements under Item 8.

Electric Operating Statistics (NSP-Minnesota)

20

Table of Contents

Electric Operating Statistics (NSP-Wisconsin)

21

Table of Contents

Electric Operating Statistics (PSCo)

(1)	Comparison of electric sales and revenues by customer class for the periods presented are impacted by a change in presentation from billing cycle to calendar cycle.

22

Table of Contents

Electric Operating Statistics (SPS)

(1)	Other electric revenues is negative in 2000 primarily due to increased provision for rate refunds.
(2)	Comparison of energy sales, customers and electric revenues by customer class for the periods presented are impacted by: 1) a change in criteria for counting customers resulting from SPS’ implementation of a new customer information system during 1999, and 2) a change in presentation from billing cycle to calendar cycle.

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 — sales, transportation, storage and ancillary services. The implementation of Order No. 636 has resulted in additional competitive pressure on all local distribution companies (LDC) to keep gas supply and transmission prices for their large customers competitive. Customers have greater ability

23

Table of Contents

      The natural gas delivery or 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 directly from, interstate pipelines, thereby avoiding the delivery charges added by the local gas utility.

      As LDC’s NSP-Minnesota, NSP-Wisconsin and PSCo provide unbundled 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 make them economically indifferent to whether gas has been sold and transported or merely transported. However, some transportation customers may have greater opportunities or incentives to physically bypass the LDC’s distribution system.

      PSCo has participated fully in state regulatory and legislative efforts to develop a framework for extending unbundling down to the residential and small commercial level. PSCo supported a gas unbundling bill, passed by the Colorado Legislature 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

      Xcel Energy categorizes its gas supply requirements as firm or interruptible (customers with an alternate energy supply). The maximum daily sendout (firm and interruptible) for the combined system of NSP-Minnesota and NSP-Wisconsin was 722,992 MMBtu for 2001, which occurred on Feb. 1, 2001.

      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. Using storage reduces the need for firm pipeline capacity. These storage agreements provide storage for approximately 15 percent of annual and 23 percent of peak daily, firm requirements of NSP-Minnesota and NSP-Wisconsin.

      NSP-Minnesota and NSP-Wisconsin also own and operate two liquified 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.

      Gas utilities in Minnesota 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 filing for approval of its 2001-2002 entitlement levels is pending MPUC action.

      PSCo projects peak day gas supply requirements for firm sales and backup transportation (transportation customers contracting for firm supply backup) to be approximately 1,690,000 MMBtu. In addition, firm transportation customers hold 389,010 MMBtu of capacity without supply backup. Total firm delivery

24

Table of Contents

      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 approximately 1,220,000 MMBtu/day, which includes 797,000 MMBtu of supplies held under third-party underground storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide about 148,000 MMBtu of gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at the companies’ city gate meter stations and a small amount received directly from wellhead sources.

      PSCo has received approval to close one if its three storage facilities, Leyden Storage Field. The field’s 110,000 MMBtu peak day capacity was replaced with additional third-party storage and transportation capacity.

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

Gas Supply and Costs

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

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

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

      NSP-Minnesota and NSP-Wisconsin have firm gas transportation contracts with several pipelines, which expire in various years from 2002 through 2014. Approximately 80 percent of NSP-Minnesota and NSP-Wisconsin’s retail gas customers are served from the Northern Natural pipeline system.

      NSP-Minnesota and NSP-Wisconsin have certain gas supply and transportation agreements that include obligations for the purchase and/or delivery of specified volumes of gas or to make payments in lieu of delivery. At Dec. 31, 2001, NSP-Minnesota and NSP-Wisconsin were committed to approximately $173.8 million in such obligations under these contracts, which expire in various years from 2002 through 2014. NSP-Minnesota and NSP-Wisconsin have negotiated market out clauses in their new supply agreements, which reduce purchase obligations if NSP-Minnesota and NSP-Wisconsin no longer provide merchant gas service.

      In addition to fixed transportation charge obligations, NSP-Minnesota and NSP-Wisconsin have entered into firm gas supply agreements that provide for the payment of monthly or annual reservation charges irrespective of the volume of gas purchased. The total annual obligation is approximately $12 million. These

25

Table of Contents

      NSP-Minnesota and NSP-Wisconsin purchase firm gas supply from approximately 30 domestic and Canadian suppliers under contracts with durations of one year to 10 years. NSP-Minnesota and NSP-Wisconsin purchase no more than 20 percent of their total daily supply from any single supplier. This diversity of suppliers and contract lengths allows NSP-Minnesota and NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

      PSCo has certain gas supply and transportation agreements that include obligations for the purchase and/or delivery of specified volumes of gas or to make payments in lieu of delivery. At Dec. 31, 2001, PSCo was committed to approximately $1.0 billion in such obligations under these contracts, which expire in various years from 2002 through 2025.

      PSCo has attempted to maintain low-cost, reliable natural gas supplies by optimizing a balance of long-term and short-term gas purchases, firm transportation and gas storage contracts. PSCo also utilizes a mixture of fixed-price purchases and index-related purchases to provide a less volatile, yet market sensitive, price to its customers. During 2001, PSCo purchased natural gas from approximately 47 suppliers.

26

Table of Contents

Gas Operating Statistics (NSP-Minnesota)