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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2000

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

For the transition period from to

Commission File Number	Exact name of registrant as specified in its charter, State or other jurisdiction of incorporation or organization, Address of principal executive offices and Registrant's Telephone Number, including area code	IRS Employer Identification No.
000-31709	NORTHERN STATES POWER COMPANY (a Minnesota Corporation) 414 Nicollet Mall, Minneapolis, Minnesota 55401 Telephone (612) 330-5500	41-1967505
001-03140	NORTHERN STATES POWER COMPANY (a Wisconsin Corporation) 1414 W. Hamilton Ave., Eau Claire, Wisconsin 54701 Telephone (715) 839-2621	39-0508315
001-03280	PUBLIC SERVICE COMPANY OF COLORADO (a Colorado Corporation) 1225 17^th Street, Denver, Colorado 80202 Telephone (303) 571-7511	84-0296600
001-03789	SOUTHWESTERN PUBLIC SERVICE COMPANY (a New Mexico Corporation) Tyler at Sixth, Amarillo, Texas 79101 Telephone (303) 571-7511	75-0575400

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 /x/ No / /

Northern States Power Company (a Minnesota corporation), Northern States Power Company (a Wisconsin corporation), Public Service Company of Colorado and Southwestern Public Service Company 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, 2001:

Northern States Power Company (a Minnesota Corporation)	Common Stock, $0.01 par value	1,000,000 Shares
Northern States Power Company (a Wisconsin Corporation)	Common Stock, $100 par value	933,000 Shares
Public Service Company of Colorado	Common Stock, $0.01 par value	100 Shares
Southwestern Public Service Company	Common Stock, $1 par value	100 Shares

Index


PART I
Item 1—Business
	COMPANY OVERVIEW
	UTILITY REGULATION
		Ratemaking Principles
		Fuel, Purchased Gas and Resource Adjustment Clauses
		Regulatory Matters
	ELECTRIC UTILITY OPERATIONS
		Competition and Industry Restructuring
		Capacity and Demand
		Energy Sources
		Fuel Supply and Costs
		Nuclear Power—Operations and Waste Disposal
		Electric Operating Statistics
	GAS UTILITY OPERATIONS
		Competition and Industry Restructuring
		Capability and Demand
		Gas Supply and Costs
		Gas Operating Statistics
	ENVIRONMENTAL MATTERS
	EMPLOYEES
Item 2—Properties
Item 3—Legal Proceedings
Item 4—Submission of Matters to a Vote of Security Holders
PART II
Item 5—Market for Registrant's Common Equity and Related Stockholder Matters
Item 6—Selected Financial Data
Item 7—Management's Discussion and Analysis
Item 7A—Quantitative and Qualitative Disclosures about Market Risk
Item 8—Financial Statements and Supplementary Data
Item 9—Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
PART III
Item 10—Directors and Executive Officers of the Registrant
Item 11—Executive Compensation
Item 12—Security Ownership of Certain Beneficial Owners and Management
Item 13—Certain Relationships and Related Transactions
PART IV
Item 14—Exhibits, Financial Statement Schedules, and Reports on Form 8-K
SIGNATURES
EXHIBIT (EXCERPT)
Ratio of Earnings to Fixed Charges
Statement Pursuant to Private Securities Litigation Reform Act

This combined Form 10-K is separately filed by Northern States Power Company, a Minnesota corporation (NSP-Minnesota), Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin), Public Service Company of Colorado (PSCo) and Southwestern Public Service Company (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 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.

Item l—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, a Minnesota corporation, is a registered holding company under the Public Utility Holding Company Act (PUHCA). Each share of NCE common stock was exchanged for 1.55 shares of Xcel Energy common stock. NSP shares became Xcel Energy shares on a one-for-one basis. The merger was structured as a tax-free, stock-for-stock exchange for shareholders of both companies (except for fractional shares), and accounted for as a pooling-of-interests. 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 Company.

Xcel Energy directly owns six utility subsidiaries that serve electric and natural gas customers in 12 states. These six utility subsidiaries are Northern States Power Company, a Minnesota corporation (NSP-Minnesota), Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin), Public Service Company of Colorado (PSCo), Southwestern Public Service Company (SPS), Black Mountain Gas Company (BMG) and Cheyenne Light, Fuel and Power Company (Cheyenne). Their service territories include portions of Arizona, Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Wisconsin and Wyoming. Xcel Energy's regulated businesses also include Viking Gas Transmission Company and WestGas InterState Inc. (WGI), both interstate natural gas pipeline companies.

Xcel Energy also owns or has an interest in a number of nonregulated businesses, the largest of which is NRG Energy, Inc., a publicly traded independent power producer. At Dec. 31, 2000, Xcel Energy indirectly owned 82 percent of NRG. Xcel Energy owned 100 percent of NRG until the second quarter 2000, when NRG completed its initial public offering. During March 2001, NRG issued an additional 18.4 million shares of common stock, which caused Xcel Energy's ownership interest in NRG to decline to approximately 75 percent.

In addition to NRG, Xcel Energy's nonregulated subsidiaries include Seren Innovations, Inc. (broadband telecommunications services), e prime, inc. (natural gas marketing and trading), Planergy International Inc. (energy management, consulting and demand-side management services) and Eloigne Company (acquisition of rental housing projects that qualify for low-income housing tax credits). Xcel Energy also reports in its nonregulated activities its 50-percent stake in Yorkshire Power, a regional electricity company in the United Kingdom. Subsequent to year-end, Xcel Energy has agreed to sell a substantial portion of this investment.

Xcel Energy owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Xcel Energy Wholesale Group, Inc., Xcel Energy Markets Holdings Inc., Xcel Energy International Inc., Xcel Energy Ventures Inc., Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group Inc., Xcel Energy WYCO Inc., Xcel Energy O&M Services Inc. and Xcel Energy Services Inc. Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.

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; First Midwest Auto Park Inc., which owns and operates a parking ramp; NSP Nuclear Corp., which holds NSP-Minnesota's interest in the Nuclear Management Company; and NSP Financing I, a special purpose business 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 225,000 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 85,000 customers in Wisconsin and Michigan.

NSP-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement Company, 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 1.2 million electric customers and approximately 1.1 million gas customers in Colorado.

PSCo owns the following direct subsidiaries: 1480 Welton, Inc., which owns certain real estate interests of PSCo; P.S.R. Investments, Inc., which owns and manages permanent life insurance policies on certain employees; PS Colorado Credit Corporation, a finance company that finances certain of PSCo's current assets; and Green and Clear Lakes Company, which owns water rights. PSCo also holds a controlling interest in several other relatively small ditch and water companies whose capital requirements are not significant.

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. SPS serves approximately 390,000 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.

UTILITY REGULATION

Ratemaking Principles

The utility subsidiaries of Xcel Energy are subject to the jurisdiction of the Securities and Exchange Commission (SEC) under PUHCA. The rules and regulations under PUHCA generally limit the operations of a registered holding company to a single integrated public utility system, plus additional energy-related businesses. PUHCA rules require that transactions between affiliated companies in a registered holding company system be performed at cost, with limited exceptions.

The FERC has jurisdiction over wholesale rates for electric transmission service and 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 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 200 kilovolts (kv) 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 rate filings for calendar years 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.

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 original and appellate jurisdiction over its retail rates and services. 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 sales for resale and the transmission of electricity in interstate commerce.

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 option 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 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.

By September of each year, NSP-Minnesota is required to submit to the MPUC an annual report of the PGA factors used to bill each customer class by month for the previous year commencing July 1 and ending June 30. The report verifies whether the utility is calculating the adjustments properly and implementing them in a timely manner. In addition, the MPUC reviews procurement policies, cost-minimizing efforts, rule variances, retail transportation gas volumes, independent auditors' reports and the impact of market forces on gas costs for the coming year. The MPUC has the authority to disallow certain costs if it finds the utility was not prudent in its gas 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. 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.

During 1999, the PSCW approved a new gas cost recovery mechanism to replace the PGA. The financial impact of the gas cost recovery mechanism is substantially the same as with the former PGA.

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

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 applications must be acted upon before becoming effective.

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 in October, and otherwise as needed, to coincide with changes in purchased gas costs. Purchased gas costs and revenues received to recover such 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 in January, and otherwise as needed, 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 and a fixed annual fuel factor 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 addition, SPS revises its fixed fuel factor annually to recover projected fuel and purchased power costs as well as any over/under cost balance for the current year. SPS is required to petition for a change in the fixed fuel factor if the over/under recovery balance reaches $5 million.

Regulatory Matters

NSP-Minnesota

Conservation Recovery—NSP-Minnesota had a 4.1 percent conservation rate surcharge in place since 1998, pending resolution of the conservation incentive recovery issue. On July 31, 2000, the MPUC approved NSP-Minnesota's request to prospectively reduce the surcharge level to 0.68 percent (consistent with current costs to be recovered) and to refund cumulative overcollections of approximately $24 million. The refund occurred during December 2000. Although cash flows were reduced, NSP-Minnesota did not have any earnings impact from these actions due to accruals previously recorded. For more information, see Management's Discussion and Analysis under Item 7.

Fuel Clause Adjustment—In June 2000, the MPUC approved a change under which bills received by NSP-Minnesota's electricity customers will more accurately reflect energy costs on a timely basis. Previously, the adjustment reflected prior period costs, and it would take approximately three months for customer bills to reflect higher, or lower, fuel costs incurred by NSP-Minnesota. Under the new method, NSP-Minnesota bases the customer billing adjustment on projected energy costs for the current month, and corrects, in a subsequent month, any differences between projected costs and actual costs incurred. This improved matching between costs and usage should encourage customers to take appropriate steps to reduce energy use during peak periods—when costs are at their highest—while giving appropriate price signals when costs are lower during off-peak periods. NSP-Minnesota implemented the revised fuel clause adjustment with July 2000 billings.

Energy Cost Recovery—In April 2000, the Minnesota Office of Attorney General (OAG) filed a petition with the MPUC asking the MPUC to initiate an investigation of NSP-Minnesota's fuel and purchased energy cost recoveries under the FCA provisions of NSP's tariffs. The OAG alleged NSP-Minnesota could be improperly diverting low-cost NSP-Minnesota generation supplies to the wholesale market to increase profits, while recovering higher-cost energy purchases through the FCA. NSP-Minnesota contends that it has followed the appropriate FCA rules and regulations. In July 2000, the MPUC issued an order in which it indicated that the record before the MPUC did not reflect any specific allegations of wrongdoing. However, the MPUC instructed NSP-Minnesota and the OAG to resolve any concerns and file a report with the MPUC. The report in pending.

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. Evidentiary hearings are scheduled for April 2001 with an order likely during the second quarter of 2001.

NSP-Wisconsin

Temporary Fuel Cost Surcharge—In May 2000, the PSCW issued an order granting a fuel surcharge to increase electric rates to recover higher fuel costs. The increase was primarily the result of higher purchased power costs than were anticipated in base rates. The surcharge factor increased revenues by approximately $6.4 million in 2000 and represented an average increase for all customer classes of approximately 2 percent. The surcharge factor is expected to be effective through Dec. 31, 2001.

PSCo

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 and recommended PSCo request recovery in a later case.

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 electricity generation and fuel management activities. In June 2000, SPS filed an application for the PUCT to retrospectively review the operations of the utility's electricity generation and fuel management activities. In this application, SPS filed its reconciliation for generation and fuel management activities totaling approximately $419 million, for

the period from January 1998 through December 1999. SPS expects to be granted recovery of these costs. Final approval is pending.

SPS filed an application in July 2000 seeking to increase its fixed fuel factors as a result of recent increases in natural gas costs. In August 2000, SPS filed a second application seeking authority to surcharge approximately $26 million in fuel under-recoveries and related interest accrued through the June 2000 billing cycle over the eight months ending May 2001. In August 2000, the PUCT consolidated these two filings into one docket. SPS reached a unanimous stipulation with all parties to the case resolving all outstanding issues. This stipulation was approved by the PUCT in September 2000, which allowed the new fuel factors and surcharge factors to become effective in the October 2000 billing cycle.

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 November 2000, SPS filed an application with the PUCT seeking authority to surcharge approximately $43 million in fuel under recoveries and related interest accrued during July 2000 through September 2000. SPS reached a unanimous stipulation with all parties to the case resolving all outstanding issues. In January 2001, the PUCT approved the surcharge and required amounts be applied to customers bills over an eleven-month period starting February 2001.

For more information on regulatory matters, see Management's Discussion and Analysis under Item 7.

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.

NSP-Minnesota

Minnesota Restructuring—During the summer of 2000, the Commerce Commissioner, Attorney General, Senate Majority Leader and House Speaker all publicly identified the potential shortage in electric supply as a critical issue for the coming legislative session. Each of these leaders expressed hesitation about adopting a comprehensive restructuring proposal, but they acknowledged the need for reforms in our power supply regulatory system. The Minnesota Chamber of Commerce still intends to push for a comprehensive restructuring bill. Based on the recommendations made by the Department of Commerce in their report "Keeping the Lights On," it is likely that reform of utility taxation and generation and transmission siting will be two of the issues debated by the 2001 Legislature.

North Dakota Restructuring—In 1997, the North Dakota Legislature established an Electric Utility Committee charged with studying the impact of competition on the electric industry. The committee has six years to study the impact of competition on the electric energy industry in the state. During 2000, the committee began the study of the current tax structure on the industry. The committee was also given the responsibility for assessing the need for modifications to the Territorial Integrity Act, a law governing distribution service territories within the state. The final report presented to the legislative council made no recommendations to change the current tax structure at the present time. The committee will resume its work after the 2001 legislative session.

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 establishes performance standards for reliability, customer service, price and employee safety. The company's performance determines its allowed return on equity. The plan also includes revenue sharing and a price cap mechanism. The plan will remain in effect through 2005.

NSP-Wisconsin

Wisconsin Restructuring—During 1999, Wisconsin state lawmakers passed "Reliability 2000" legislation, which included steps necessary to further progress toward a restructured industry, eventually including allowing retail customers to choose their electric supplier. One of the provisions of the legislation establishes a public benefits fund, to be administered by the State of Wisconsin, which will use money collected from Wisconsin utilities' customers to pay for low-income assistance, conservation programs and renewable energy and environmental research programs. NSP-Wisconsin began collecting the public benefits surcharge from its Wisconsin customers in October 2000.

In April 1998, Wisconsin state legislators enacted a law that includes provisions that require the PSCW to order a public utility that owns transmission facilities in Wisconsin to transfer control of its transmission facilities to an independent system operator (ISO) or divest its interest in its transmission facilities to an independent transmission company (ITC) by June 2000. NSP-Minnesota and NSP-Wisconsin joined the Midwest ISO (MISO) in 1999 and filed for PSCW and FERC approval in March 2000. The MISO is not expected to be operational until November 2001. In June 2000, the PSCW issued an order that effectively waived the deadline for the state's five major utilities, including NSP-Wisconsin, to relinquish transmission system control. In October 2000, the PSCW issued an order authorizing NSP-Wisconsin's transfer of operating control of its transmission system to the MISO.

Michigan Restructuring—In June 2000, Michigan's "Customer Choice and Electricity Reliability Act," became law. The passage of the Act means there will be customer choice for all customers in Michigan, including NSP-Wisconsin's customers in the Upper Peninsula, starting January 2002. Key elements of the law include developing distribution reliability and performance standards and environmental and fuel disclosure standards, codes of conduct, customer and employee education

programs and an Upper Peninsula Market Power Study. The Act also contains a number of consumer protection provisions dealing with cramming, slamming and low-income energy assistance. NSP-Wisconsin filed its preliminary restructuring plan in October 2000 and revisions to the preliminary restructuring plan in February 2001. NSP-Wisconsin expects to file its unbundled rates by June 2001. The five-percent rate reduction and rate freeze ordered in the Act does not apply to NSP-Wisconsin or other utilities with less than 1 million customers in Michigan.

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.

SPS

New Mexico Restructuring—In April 1999, New Mexico enacted the Electric Utility Restructuring Act of 1999, which provides for customer choice. The legislation provides for recovery of no less than 50 percent of stranded costs for all utilities. Transition costs must be approved by the NMPRC prior to being recovered through a non-bypassable wires charge, which must be included in transition plan filings. SPS must separate its utility operations into at least two entities: energy generation and competitive services, and transmission and distribution utility services, either by the creation of separate affiliates that may be owned by a common holding company or by the sale of assets to one or more third parties. A regulated company, in general, is prohibited from providing unregulated services. In May 2000, the NMPRC approved:

•: customer choice for residential, small commercial and educational customers by January 2002;
•: customer choice for commercial and industrial customers by July 2002; and
•: completion of SPS corporate separation by August 2001.

The NMPRC has reopened its electric restructuring rulemakings to consider the impacts on New Mexico electricity markets arising from the volatile California electricity market conditions. In addition, in February 2001, the New Mexico Senate approved a bill that would delay the implementation of restructuring and retail choice until 2007. The House has yet to act on the proposal to delay. We cannot predict the changes that may result from reconsideration of the restructuring legislation or the NMPRC's reconsideration of its regulations as a result of the continuing and significant conditions in the California markets.

Texas Restructuring—In June 1999, an electric utility restructuring act (SB-7) was passed in Texas, which provides for the implementation of retail competition for most areas of the state, including SPS' service area, beginning January 2002. The PUCT can delay the date for full retail competition if a power region is unable to offer fair competition and reliable service during the 2001 pilot projects. The legislation requires:

•: a rate freeze for all customers until January 2002;
•: an annual earnings test through 2001;
•: a 6-percent rate reduction for those residential and small commercial customers who choose not to switch suppliers at the start of retail competition;
•: the unbundling of business activities, costs and rates relating to generation, transmission and distribution, and retail services;
•: reductions in nitrogen oxide and sulfur dioxide emissions; and

•: the recovery of stranded costs.

SB-7 requires each utility to unbundle its business activities into three separate legal entities: a power generation company, a regulated transmission and distribution company, and a retail electric provider. SB-7 limits the market share that a single generation provider can control to 20 percent of the generating capacity within a qualified power region. The establishment of a qualified power region with multiple generation suppliers is required under SB-7 in order to implement full retail competition. SPS must return any excess earnings indicated in the annual earnings tests above its last allowed rate of return for 1999, 2000 and 2001 or alternatively may direct any excess earnings to improvements in transmission and distribution facilities, to capital expenditures to improve air quality or to accelerate the amortization of regulatory assets, subject to PUCT approval.

The Texas Legislature is currently considering amendments to SB-7 that would delay the implementation of business separation and customer choice in SPS' market area for five years.

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

Kansas Restructuring—In 1999, the Kansas Corporation Commission investigated the adequacy of generation capacity of Kansas utilities. The Commission ordered the staff to continually monitor the generation capacity situation in Kansas, ensure the regular filing of information by utilities to meet their responsibility to provide electric service to retail customers and consider the opening of a new docket for conservation appeals.

Oklahoma Restructuring—The Electric Restructuring Act of 1997 was enacted in Oklahoma during 1997. This legislation directs a series of studies, which will define the orderly transition to consumer choice of electric energy supplier by July 1, 2002. The Electric Restructuring Act was modified during 1998 to clarify terms used in the original bill, as well as advance timelines for studies of the Joint Electric Utility Task Force in order to meet the stated implementation date. In 1998, this task force began the formation of groups, which will examine numerous restructuring issues. A report was issued in 1999. The 2001 legislative session will consider the task force's findings as it considers issues related to implementing customer choice in 2002.

Capacity and Demand

Assuming normal weather during 2001, 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 2001 is listed below.

	System Peak Demand (Mw)
Operating company	1998	1999	2000	2001
NSP System	7,660	7,990	7,936	7,747
PSCo	4,771	4,854	5,406	5,519
SPS	3,933	3,937	3,870	3,583

The peak demand for the NSP System, PSCo and SPS all typically occurs in the summer. The 2000 system peak demand for the NSP System occurred on Aug. 14, 2000. The 2000 system peak demand for PSCo occurred on Aug. 9, 2000. The 2000 system peak demand for SPS occurred on Aug. 3, 2000.

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

During 2000, NSP-Minnesota filed an electric resource plan for the NSP System with the MPUC for the period 2000 to 2015. The plan describes how Xcel Energy intends to meet the energy needs of the NSP System and includes an approximate schedule of the timing of resource solicitation to meet such needs. The plan contains conservation programs to reduce the 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:

•: 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 the programs for achieving the mandated renewable energy sources of 425 megawatts of wind and 125 megawatts of biomass (NSP-Minnesota contracted for all 125 megawatts of biomass energy, but 80 megawatts of wind energy remains to be contracted); 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.

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 910 megawatts by 2015 through conservation and load management;
•: 425 megawatts of wind energy and 125 megawatt of biomass energy under contract by 2002; and
•: acquisition of competitively priced resources through competitive bidding.

The MPUC is currently reviewing this resource plan. Key issues are the amount of demand side management investment, nuclear spent fuel storage and its impact on future resource needs and assumptions made regarding unaccounted for operating costs of wind. NSP-Minnesota expects the MPUC to issue an order about this resource plan in mid-2001.

PSCo Resource Plan

PSCo estimates it will purchase approximately 37 percent of its total electric system energy input for 2001. Approximately 36 percent of the total system capacity for the summer 2001 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 recently completed a solicitation process that will add approximately 1,800 megawatts of resources to its system over the 2002-2005 time period. PSCo expects that purchased capacity will continue to meet a significant portion of system requirements at least through 2016.

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 Btu of each category of fuel consumed by the system for electric generation during the years indicated, the percentage of total fuel

requirements represented by each category of fuel and the weighted average cost of all fuels during such years.

	Coal*			Nuclear
	Coal*			Nuclear			Average Fuel Cost
NSP System generating plants:	Cost		Percent	Cost		Percent	Average Fuel Cost
2000	$	1.11	60%	$	0.45	36%	$	0.91
1999		1.10	58%		0.48	38%		0.88
1998		1.00	60%		0.47	35%		0.85

*: Includes refuse-derived fuel and wood

	Coal
	Coal					Gas Percent	Average Fuel Cost
PSCo generating plants:	Cost		Percent	Cost		Gas Percent	Average Fuel Cost
2000	$	0.91	87%	$	3.97	13%	$	1.30
1999		0.90	92%		2.52	8%		1.04
1998		0.93	95%		2.46	5%		1.00

				Gas
			Coal Percent	Gas			Average Fuel Cost
SPS generating plants:	Cost		Coal Percent	Cost		Percent	Average Fuel Cost
2000	$	1.45	70%	$	4.23	30%	$	2.28
1999		1.41	70%		2.38	30%		1.70
1998		1.60	67%		2.19	33%		1.80

NSP-Minnesota and NSP-Wisconsin

NSP-Minnesota and NSP-Wisconsin normally maintain between 20 and 40 days of coal inventory at each plant site. NSP-Minnesota and NSP-Wisconsin have long-term contracts providing for the delivery of up to 100 percent of 2001 coal requirements and up to 70 percent of their 2002 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 2001 will have a sulfur content of less than 1 percent. NSP-Minnesota and NSP-Wisconsin have contracts for a maximum of 21.4 million tons of low-sulfur coal for the next two years. The contracts are with two Montana coal suppliers and four Wyoming suppliers. NSP-Minnesota and NSP-Wisconsin could purchase approximately 5 percent of their coal requirements in the spot market in 2001 and 45 percent of coal requirements in 2002 if spot prices are more favorable than contracted prices.

Estimated coal requirements at NSP-Minnesota's major coal-fired generating plants and the coal supply for such requirements are approximately 12 million tons per year, which is covered by contracts with expiration dates that vary between 2001 and 2003.

NSP-Minnesota and NSP-Wisconsin's current fuel oil inventory is adequate and they have access to additional spot purchase supplies to meet anticipated 2001 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 100 percent of uranium, conversion and enrichment requirements through the year 2001. These contracts expire at varying times between 2001 and 2005. The overlapping nature of contract commitments will allow NSP-Minnesota to maintain 50 percent to 100 percent coverage beyond 2001. 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 seven long-term contracts with suppliers operating in Colorado and Wyoming. During 2000, PSCo's coal requirements for existing plants were approximately 9.9 million tons, a substantial portion of which was supplied pursuant to long-term supply contracts. Coal supply inventories at Dec. 31, 2000, were approximately 33 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. More than 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 2001 and 2002. Any remaining requirements may be purchased from this contract or the spot market. PSCo has contracted for long-term coal supplies to supply approximately 40 percent of the Cherokee and Valmont Stations' projected requirements in 2001. In addition, PSCo has contracted for substantially all of Cherokee's and Valmont's remaining projected 2001 coal needs.

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 80 percent of Arapahoe Station's projected requirements for 2001. Any remaining Arapahoe Station requirements will be procured via spot 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 on a competitive basis 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, 2000, coal inventories at the Harrington and Tolk sites were approximately 30 and 32 days supply, respectively. TUCO has a long-term coal supply agreement to supply approximately 55 percent of Harrington's projected requirements in 2001. 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 55 percent of SPS' gas requirements during 2000 were purchased under spot agreements.

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 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.

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 13 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, 2000, 12 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 March 2001, NSP-Minnesota signed a contract with Steam Generator 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 25-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. The four companies operate seven nuclear units at five sites, with a total generation capacity exceeding 3,650 megawatts.

During the second quarter of 2000, the Nuclear Regulatory Commission (NRC) approved requests by NMC's four affiliated utilities to transfer operating authority for their five nuclear plants to NMC. NRC action paves the way for NMC to assume management of operations and maintenance at the five plants. The NRC also is considering requests from three intervenors for hearings regarding NSP-Minnesota's application. NMC responsibilities will include oversight of on-site dry storage facilities for used nuclear fuel at the Point Beach and Prairie Island nuclear plants. Utility plant owners will continue to own the plants, control all energy produced by the plants and retain responsibility for nuclear liability insurance and decommissioning costs. The transfer of operating authority will formally establish NMC as an operating company, with a senior management team focused on sharing best practices. Existing personnel will continue to provide day-to-day plant operations, with the additional benefit of tapping into ideas from all NMC-operated plants for improved safety, reliability and operational performance.

During the third quarter of 2000, NMC and Consumers Energy (CE) reached an agreement for the NMC to operate CE's 789-megawatt Palisades nuclear plant in Covert, Mich. The addition of Palisades gives NMC 4,500 megawatts of generation, making it the sixth largest operator of nuclear plants in the United States.

For further discussion of nuclear issues, see Note 12 and Note 13 to the Financial Statements under Item 8.

Electric Operating Statistics (NSP-Minnesota)

			Year Ended Dec. 31,
			2000		1999			1998
Electric sales (millions of Kwh):
	Residential			8,995		8,642			8,420
	Commercial			5,610		5,163			5,060
	Industrial			17,925		17,555			17,385
	Public authorities and other			280		285			286

		Total retail		32,810		31,645			31,151
	Sales for resale			6,764		6,252			5,842

		Total energy sold		39,574		37,897			36,993

Number of customers at end of period:
	Residential			1,137,649		1,115,974			1,099,103
	Commercial			126,321		131,154			126,500
	Industrial			7,895		8,989			8,746
	Public authorities and other			5,408		5,330			5,232

		Total retail		1,277,273		1,261,447			1,239,581
	Wholesale			80		72			68

		Total customers		1,277,353		1,261,519			1,239,649

Electric revenues (thousands of dollars):
	Residential		$	705,502	$	682,783		$	653,625
	Commercial			368,964		344,245			330,526
	Industrial			876,303		868,700			829,282
	Public authorities and other			27,218		27,268			26,800
	Conservation accrual adjustment			—		(71,348	)		—

		Total retail		1,977,987		1,851,648			1,840,233
	Wholesale			179,770		152,442			133,953
	Other electric revenues			254,126		263,123			269,587

		Total electric revenues	$	2,411,883	$	2,267,213		$	2,243,773

Kwh sales per retail customer				25,688		25,087			25,130
Revenue per retail customer			$	1,548.60	$	1,467.88		$	1,484.56
Residential revenue per Kwh				7.84¢		7.90¢			7.76¢
Commercial revenue per Kwh				6.58¢		6.67¢			6.53¢
Industrial revenue per Kwh				4.89¢		4.95¢			4.77¢
Wholesale revenue per Kwh				2.66¢		2.44¢			2.29¢

Electric Operating Statistics (NSP-Wisconsin)

			Year Ended Dec. 31,
			2000		1999		1998
Electric sales (millions of Kwh):
	Residential			1,774		1,731		1,706
	Commercial			1,027		954		939
	Industrial			2,759		2,709		2,694
	Public authorities and other			40		40		41

		Total retail		5,600		5,434		5,380
	Sales for resale			473		471		462

		Total energy sold		6,073		5,905		5,842

Number of customers at end of period:
	Residential			191,287		190,926		187,977
	Commercial			31,588		29,775		29,036
	Industrial			1,487		1,471		1,491
	Public authorities and other			1,047		1,019		1,011

		Total retail		225,409		223,191		219,515
	Wholesale			10		10		10

		Total customers		225,419		223,201		219,525

Electric revenues (thousands of dollars):
	Residential		$	131,201	$	126,744	$	121,178
	Commercial			65,992		61,375		59,218
	Industrial			129,306		125,129		120,665
	Public authorities and other			4,450		4,400		4,254

		Total retail		330,949		317,648		305,315
	Wholesale			16,936		17,292		16,769
	Sales to NSP-Minnesota			73,425		74,214		73,674
	Other electric revenues			3,167		2,378		2,739

		Total electric revenues	$	424,477	$	411,532	$	398,497

Kwh sales per retail customer				24,843		24,463		24,509
Revenue per retail customer			$	1,468.22	$	1,423.21	$	1,390.86
Residential revenue per Kwh				7.40¢		7.32¢		7.10¢
Commercial revenue per Kwh				6.43¢		6.43¢		6.30¢
Industrial revenue per Kwh				4.69¢		4.62¢		4.48¢
Wholesale revenue per Kwh				3.58¢		3.67¢		3.63¢

Electric Operating Statistics (PSCo)

			Year Ended Dec. 31,
			2000		1999		1998
Electric sales (millions of Kwh) (1):
	Residential			7,647		6,997		6,821
	Commercial			12,183		11,575		10,908
	Industrial			4,850		4,552		4,861
	Public authorities and other			252		233		219

		Total retail		24,932		23,357		22,809
	Sales for resale			9,148		5,413		8,309

		Total energy sold		34,080		28,770		31,118

Number of customers at end of period:
	Residential			1,019,961		994,318		970,217
	Commercial			133,669		130,663		127,386
	Industrial			278		309		325
	Public authorities and other			86,364		84,675		82,764

		Total retail		1,240,272		1,209,965		1,180,692
	Wholesale			96		54		50

		Total customers		1,240,368		1,210,019		1,180,742

Electric revenues (thousands of dollars) (1):
	Residential		$	558,153	$	527,396	$	516,475
	Commercial			646,818		617,620		595,092
	Industrial			197,693		194,805		208,478
	Public authorities and other			32,185		30,862		29,959

		Total retail		1,434,849		1,370,683		1,350,004
	Wholesale			576,404		175,688		268,705
	Other electric revenues			2,479		12,004		16,864

		Total electric utility revenues	$	2,013,732	$	1,558,375	$	1,635,573

Kwh sales per retail customer				20,102		19,304		19,319
Revenue per retail customer			$	1,156.88	$	1,132.83	$	1,143.40
Residential revenue per Kwh				7.30¢		7.54¢		7.57¢
Commercial revenue per Kwh				5.31¢		5.34¢		5.46¢
Industrial revenue per Kwh				4.08¢		4.28¢		4.29¢
Wholesale revenue per Kwh				6.30¢		3.25¢		3.23¢

(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.

Electric Operating Statistics (SPS)

			Year Ended Dec. 31,
			2000			1999		1998
Electric sales (millions of Kwh) (2):
	Residential			3,467			3,104		3,204
	Commercial			5,424			3,469		3,086
	Industrial			6,959			7,708		8,504
	Public authorities and other			608			549		636

		Total retail		16,458			14,830		15,430
	Sales for resale			9,898			8,864		8,123

		Total energy sold		26,356			23,694		23,553

Number of customers at end of period (2):
	Residential			311,660			308,162		312,539
	Commercial			74,067			71,392		58,535
	Industrial			276			185		12,622
	Public authorities and other			5,705			4,834		824

		Total retail		391,708			384,573		384,520
	Wholesale			34			53		267

		Total customers		391,742			384,626		384,787

Electric revenues (thousands of Dollars) (2):
	Residential		$	198,123		$	176,249	$	192,881
	Commercial			269,526			195,170		167,350
	Industrial			189,193			223,686		304,132
	Public authorities and other			30,275			28,392		32,958

		Total retail		687,117			623,497		697,321
	Wholesale			393,502			274,873		280,922
	Other electric revenues (1)			(1,039	)		27,567		(27,056	)

		Total electric revenues	$	1,079,580		$	925,937	$	951,187

Kwh sales per retail customer				42,013			38,565		40,133
Revenue per retail customer			$	1,754.16		$	1,621.27	$	1,813.48
Residential revenue per Kwh				5.72¢			5.68¢		6.02¢
Commercial revenue per Kwh				4.97¢			5.63¢		5.42¢
Industrial revenue per Kwh				2.72¢			2.90¢		3.58¢
Wholesale revenue per Kwh				3.98¢			3.10¢		3.46¢

(1): Other electric revenues is negative in 1998 primarily due to the recognition of lower deferred fuel revenues resulting from cost reductions for fuel used in generation.
(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's implementation of a new customer information system during 1999, 2) effective August 1999, a reclassification to include only large commercial and industrial customers within the industrial category, to be consistent with PSCo and recommended utility industry guidelines, and 3) 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 unbundling 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 to buy gas directly from suppliers and arrange their own pipeline and LDC transportation service. Changes in regulatory policies and market forces have shifted the industry from traditional bundled gas sales service to an unbundled transportation and market based commodity service.

The natural gas delivery 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. The gas utility subsidiaries of Xcel Energy have and will continue to aggressively pursue the retention of all customers on their systems.

NSP-Minnesota and NSP-Wisconsin provide unbundled transportation service to large customers. Transportation service does not have an adverse effect on earnings because NSP-Minnesota and NSP-Wisconsin's sales and transportation rates have been designed to make NSP-Minnesota and NSP-Wisconsin 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 distribution system.

PSCo provides unbundled transportation service to large customers. and 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 open its natural gas supply business to competition and continues to evaluate its business opportunities for doing so.

PSCo extends and operates its distribution systems primarily by virtue of non-exclusive franchises granted by the various cities and towns. The PCUC approves such franchise agreements. Because the franchises are non-exclusive, PSCo can be faced with the threat of intrusion into their gas territory by third parties. PSCo holds territorial certificates for a portion of their gas service territory, giving them the exclusive right to extend their distribution system and provide natural gas sales and transportation service. However, for the majority of their gas service territory, no such territorial certificates exist. PSCo has filed with the CPUC an application to certify its gas service territory along the front range of Colorado. PSCo is pursuing settlement negotiations and expects a resolution during 2001.

Capability and Demand

NSP-Minnesota and NSP-Wisconsin

NSP-Minnesota and NSP-Wisconsin 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 730,026 mmBtu for 2000, which occurred on Dec. 11, 2000.

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 630,000 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 16 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 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 mcf 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 July 2000, the MPUC approved NSP's 1999-2000 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 2000-2001 entitlement levels is pending MPUC action.

PSCo

PSCo projects peak day gas supply requirements for firm sales and backup transportation (transportation customers contracting for firm supply backup) to be 1,596,640 mmBtu. In addition, firm transportation customers hold 379,720 mmBtu of capacity without supply backup. Total firm delivery obligations for PSCo is 1,976,360 mmBtu per day. The maximum daily delivery for 2000 (firm and interruptible services) was 1,540,519 mmBtu on Dec. 11, 2000.

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 1,153,208 mmBtu/day, which includes 716,614 mmBtu of supplies held under third-party storage agreements. In addition, PSCo operates three company-owned storage facilities, which provide about 147,980 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' citygate meter stations and a small amount received directly from wellhead sources.

PSCo has received approval to abandon one if its three storage facilities, Leyden Storage Field, beginning October 2001. The field's 110,000 mmBtu peak day capacity will be replaced in 2001 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. PSCo has filed the required Plans with the CPUC, which is reviewing the gas purchase report for the period July 1, 1999, through June 30, 2000.

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.

	NSP-Minnesota		NSP-Wisconsin		PSCo
2000	$	4.56	$	4.71	$	4.48
1999	$	2.97	$	3.32	$	2.85
1998	$	2.83	$	3.18	$	2.64

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

NSP-Minnesota and NSP-Wisconsin

NSP-Minnesota and NSP-Wisconsin have firm gas transportation contracts with several pipelines, which expire in various years from 2001 through 2013. Approximately 80 percent of NSP-Minnesota and NSP-Wisconsin's retail gas customers are served from the Northern Natural pipeline system.

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 $18 million. These agreements allow NSP-Minnesota and NSP-Wisconsin to purchase natural gas at a high load factor at rates below the prevailing market price, reducing the total cost per mmBtu.

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, 2000, NSP-Minnesota and NSP-Wisconsin were committed to approximately $221 million in such obligations under these contracts, which range from the years 2001-2013. 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.

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.

NSP-Minnesota and NSP-Wisconsin have completed substantially all of their obligations related to gas supply transportation and storage contracts that resulted from FERC Order 636.

PSCo

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. During 2000, PSCo purchased natural gas from approximately 47 suppliers.

PSCo has completed substantially all of their obligations related to gas supply transportation and storage contracts that resulted from FERC Order 636. PSCo has entered into new contracts for firm transportation and gas storage services. Adequate supplies of natural gas are currently available for delivery within the region. PSCo continually evaluates the natural gas markets and procure supplies, as needed, to meet current and anticipated customer demand.

Gas Operating Statistics (NSP-Minnesota)

			Year Ended Dec. 31,
			2000	1999	1998
Gas deliveries (thousands of Dth):
	Residential		38,461	34,478	31,949
	Commercial and industrial		41,257	39,441	37,601
	Other		1,225	1,691	3,327

		Total retail	80,943	75,610	72,877
	Transportation and other		9,510	12,463	14,337

		Total deliveries	90,453	88,073	87,214

Number of customers at end of period:
	Residential		371,894	368,468	351,459
	Commercial and industrial		35,381	40,383	33,891

		Total retail	407,275	408,851	385,350
	Transportation and other		51	51	49

		Total customers	407,326	408,902	385,399

Gas Revenues (thousands of dollars):
	Residential		$285,868	$196,190	$187,736
	Commercial and industrial		227,414	150,570	144,679
	Other		1,569	1,495	4,721

		Total retail	514,851	348,255	337,136
	Transportation and other		21,849	17,580	23,432

		Total gas revenues	$536,700	$365,835	$360,568

Dth sales per retail customer			198.74	184.93	189.12
Revenue per retail customer			$1,264.14	$851.79	$874.88
Residential revenue per Dth			$7.43	$5.69	$5.88
Commercial and industrial revenue per Dth			$5.51	$3.82	$3.85
Transportation and other revenue per Dth			$2.30	$1.41	$1.63

Gas Operating Statistics (NSP-Wisconsin)

			Year Ended Dec. 31,
			2000	1999	1998
Gas deliveries (thousands of Dth):
	Residential		6,281	5,744	5,168
	Commercial and industrial		11,544	10,678	9,808
	Other		868	1,263	1,704

		Total retail	18,693	17,685	16,680
	Transportation and other		1,353	1,310	1,272

		Total deliveries	20,046	18,995	17,952

Number of customers at end of period:
	Residential		75,449	75,224	72,673
	Commercial and industrial		10,626	10,503	10,277

		Total retail	86,075	85,727	82,950
	Transportation and other		—	12	9

		Total customers	86,075	85,739	82,959

Gas revenues (thousands of dollars):
	Residential		$49,156	$37,732	$35,034
	Commercial and industrial		58,249	41,562	39,049
	Other		1,946	2,891	4,571

		Total retail	109,351	82,185	78,654
	Transportation and other		672	190	191

		Total gas revenues	$110,023	$82,375	$78,845

Dth sales per retail customer			217.17	206.29	201.08
Revenue per retail customer			$1,270.42	$958.68	$948.21
Residential revenue per Dth			$7.83	$6.57	$6.78
Commercial and industrial revenue per Dth			$5.05	$3.89	$3.98
Transportation and other revenue per Dth			$0.50	$0.15	$0.15

Gas Operating Statistics (PSCo)

			Year Ended Dec. 31,
			2000	1999	1998
Gas deliveries (thousands of Dth):
	Residential		90,270	82,594	81,666
	Commercial and industrial		41,165	38,419	39,376

		Total retail	131,435	121,013	121,042
	Transportation and other		117,992	89,286	90,746

		Total deliveries	249,427	210,299	211,788

Number of customers at end of period:
	Residential		1,001,951	966,515	932,829
	Commercial and industrial		94,516	92,515	90,858

		Total retail	1,096,467	1,059,030	1,023,687
	Transportation and other		3,713	3,083	2,731

		Total customers	1,099,640	1,062,113	1,026,418

Gas revenues (thousands of dollars):
	Residential		$526,409	$442,578	$423,875
	Commercial and industrial		208,589	174,671	175,291

		Total retail	734,998	617,249	599,166
	Transportation and other		52,112	40,573	40,898

		Total gas revenues	$787,110	$657,822	$640,064

Dth sales per retail customer			119.87	114.27	118.24
Revenue per retail customer			$67.03	$58.28	$58.53
Residential revenue per Dth			$5.83	$5.36	$5.19
Commercial and industrial revenue per Dth			$5.07	$4.55	$4.45
Transportation and other revenue per Dth			$0.44	$0.45	$0.45

ENVIRONMENTAL MATTERS

Certain of Xcel Energy's subsidiary facilities are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. Xcel Energy's utility subsidiaries have received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Company facilities have been designed and constructed to operate in compliance with applicable environmental standards.

Xcel Energy and its subsidiaries strive to comply with all environmental regulations applicable to their operations. However, it is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, generally, what effect future laws or regulations may have upon their operations. For more information on Environmental Matters, see Note 12 to the Financial Statements under Item 8 and Management's Discussion and Analysis under Item 7.

EMPLOYEES

The number of Xcel Energy utility subsidiary employees at Dec. 31, 2000, is presented in the following table. Of the employees listed in the table, approximately 5,350, or 46 percent, are covered under collective bargaining agreements. Xcel Energy Service Co. employees provide service to Xcel Energy's utility subsidiaries.


NSP-Minnesota		4,575
NSP-Wisconsin		949
PSCo		2,779
SPS		1,189
Xcel Energy Service Co.		2,219

Item 2—Properties

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

Electric utility generating stations:

NSP — Minnesota

Station and Unit		Fuel	Installed	Summer 2000 Capability (Mw)
Sherburne
	Unit 1	Coal	1976	712
	Unit 2	Coal	1977	706
	Unit 3	Coal	1987	522
Prairie Island
	Unit 1	Nuclear	1973	525
	Unit 2	Nuclear	1974	524
Monticello		Nuclear	1971	572
King		Coal	1968	571
Black Dog
	2 Units	Coal/Natural Gas	1955-1960	284
High Bridge
	2 Units	Coal	1956-1959	269
Riverside
	2 Units	Coal	1964-1987	384
Other		Various	Various	1,080

			Total	6,149

NSP-Minnesota's 59 percent of Sherco unit 3's total capability

NSP — Wisconsin

Station and Unit			Fuel	Installed	Summer 2000 Capability (Mw)
Combustion Turbine:
	Flambeau Station		Natural Gas/Oil	1969	14
	Wheaton
		6 Units	Natural Gas/Oil	1973	345
	French Island
		2 Units	Oil	1974	154
Steam:
	Bay Front
		3 Units	Coal/Wood/Natural Gas	1945-1960	74
	French Island
		2 Units	Wood/RDF	1940-1948	29
Hydro:
	19 Plants			Various	249

				Total	865

RDF is refuse derived fuel, made from municipal solid waste

PSCo

Station and Unit			Fuel	Installed		Summer 2000 Capability (Mw)
Steam:
	Arapahoe
		4 Units	Coal	1950-1955		246
	Cameo
		2 Units	Coal	1957-1960		73
	Cherokee
		4 Units	Coal	1957-1968		717
	Comanche
		2 Units	Coal	1973-1975		660
	Craig
		2 Units	Coal	1979-1980	(a)	83
	Hayden
		2 Units	Coal	1965-1976	(b)	237
	Pawnee		Coal	1981		505
	Valmont		Coal	1964		186
	Zuni
		3 Units	Natural Gas/Oil	1948-1954		86
Combustion Turbines:
	Fort St. Vrain
		4 Units	Natural Gas	1979-1998		465
	Various Locations
		6 Units	Natural Gas	Various		159
Hydro:
	Various Locations
		14 Units(c)		Various		37
	Cabin Creek			1967		210
		Pumped Storage
Diesel Generators:
	Cherokee
		2 Units		1967		6

				Total		3,670

(a): Based on PSCo ownership interest of 9.72 percent
(b): Based on PSCo ownership interest of 75.5 percent of unit 1 and 37.4 percent of unit 2
(c): Includes one station (2 units) not owned by PSCo but operated under contract

SPS

Station and Unit			Fuel	Installed	Summer 2000 Capability (Mw)
Steam:
	Harrington
		3 Units	Coal	1976-1980	1,066
	Tolk
		2 Units	Coal	1982-1985	1,080
	Jones
		2 Units	Natural Gas	1971-1974	486
	Plant X
		4 Units	Natural Gas	1952-1964	442
	Nichols
		3 Units	Natural Gas	1960-1968	457
	Cunningham
		2 Units	Natural Gas	1957-1965	267
	Maddox		Natural Gas	1983	118
	CZ-2		Purchased Steam	1979	26
	Moore County		Natural Gas	1954	48
Gas Turbine:
	Carlsbad		Natural Gas	1977	13
	CZ-1		Hot Nitrogen	1965	13
	Maddox		Natural Gas	1983	66
	Riverview		Natural Gas	1973	23
	Cunningham		Natural Gas	1998	220

				Total	4,325

Electric utility overhead and underground transmission and distribution lines at Dec. 31, 2000:

Pole Miles	NSP-Minnesota	NSP-Wisconsin	PSCo	SPS
500 kilovolt (kv)	265	0	0	0
345 kv	568	166	112	319
230 kv	284	0	1,683	1,582
161 kv	59	280	0	0
138 kv	0	0	65	0
115 kv	1,206	449	772	2,459
Less than 115 kv	39,473	11,162	22,843	17,817

Electric utility transmission and distribution substations at Dec. 31, 2000:

Quantity		NSP-Minnesota		NSP-Wisconsin		PSCo		SPS
		349		205		367		304

Gas utility mains at Dec. 31, 2000:

Miles		NSP-Minnesota		NSP-Wisconsin		PSCo		SPS
Transmission		116		0		2,212		0
Distribution		8,384		1,870		16,253		0

Item 3—Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against the utility subsidiaries of Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters.

NSP-Minnesota

On June 8, 1998, NSP-Minnesota filed a complaint in the Court of Federal Claims against the DOE requesting damages in excess of $1 billion for the DOE's partial breach of the Standard Contract. NSP-Minnesota requested damages consisting of the costs of storage of spent nuclear fuel at the Prairie Island nuclear generating plant, anticipated costs related to the Private Fuel Storage, LLC and costs relating to the 1994 state legislation limiting the number of casks that can be used to store spent nuclear fuel at Prairie Island. On April 6, 1999, the Court of Federal Claims dismissed NSP-Minnesota's complaint. On May 20, 1999, NSP-Minnesota appealed to the Court of Appeals for the Federal Circuit. On Aug. 31, 2000, the Court of Appeals for the Federal Circuit reversed and remanded to the Court of Federal Claims. On Dec. 26, 2000, NSP-Minnesota filed a motion with the Court of Federal Claims to amend its complaint and renew its motion for summary judgment on the DOE's liability. These motions are pending before the Court of Federal Claims. On Jan. 9, 2001, the DOE filed a motion with the Chief Judge for the Court of Federal Claims asking that all cases against the DOE arising out of alleged breaches of the Standard Contract be reassigned to one judge. The DOE also asked for the extraordinary remedy of binding parties not currently party to an action before the Court of Claims to a determination in the proposed consolidated action. This motion is pending before the Court of Federal Claims.

In April 1997, a fire damaged several buildings in downtown Grand Forks, N. D., during a flood in the city. On July 23, 1998, the St. Paul Mercury Insurance Co. commenced a lawsuit against NSP-Minnesota for damages in excess of $15 million. The suit was filed in the District Court in Grand Forks County in North Dakota. The insurance company alleged the fire was electrical in origin and that NSP-Minnesota was legally responsible for the fire because it failed to shut off electrical power to downtown Grand Forks during the flood and prior to the fire. Seven additional lawsuits were filed against NSP-Minnesota by insurance companies that insured businesses damaged by the fire. One additional lawsuit was filed by a bank. The total of damages sought by all these lawsuits was in excess of $30 million. NSP-Minnesota denied any liability. On Sept. 8, 2000, the jury returned a defense verdict in favor of NSP-Minnesota. The plaintiffs did not appeal this verdict.

NSP-Wisconsin

In 1997, NSP-Wisconsin was served with a summons and complaint on behalf of the owners of Schachtner Farms located in Deer Park, Wis. The complaint alleged that stray voltage from NSP-Wisconsin's system harmed their dairy herd, resulting in lost milk production, injury to the dairy herd, lost profits and increased veterinary expenses. On Nov. 23, 1999, the jury returned a verdict finding NSP-Wisconsin negligent and awarding Schachtner Farms $850,000 for economic damages and $200,000 for inconvenience, annoyance and loss of use and enjoyment of their property plus costs and interest. The Court trebled the damages because the jury found that NSP-Wisconsin was willful, wanton or reckless in its failure to provide adequate service to the farm. NSP-Wisconsin has appealed the decision to the Court of Appeals, Third District, of the State of Wisconsin. The claim was resolved on Dec. 20, 2000, on a confidential basis. NSP-Wisconsin's contribution to the settlement was reduced by insurance coverage.

For a discussion of other legal claims and environmental proceedings, see Note 14 to the Financial Statements under Item 8, incorporated by reference. For a discussion of proceedings involving utility

rates, see "Regulatory Matters" under Item 1, and Management's Discussion and Analysis under Item 7, all incorporated by reference.

Item 4—Submission of Matters to a Vote of Security Holders

This is omitted per conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

PART II

Item 5—Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters

This is not applicable as NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are wholly owned subsidiaries.

Item 6—Selected Financial Data

This is omitted per conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Item 7—Management's Discussion and Analysis

Discussion of financial condition and liquidity for the utility subsidiaries of Xcel Energy are omitted per conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management's narrative analysis and the results of operations for the current year as set forth in general instructions I (2) (a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Forward Looking Information

The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of Xcel Energy's utility subsidiaries during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited Consolidated Financial Statements and Notes.

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "estimate," "expect," "objective," "outlook," "possible," "potential" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:

•: general economic conditions, including their impact on capital expenditures
•: business conditions in the energy industry
•: competitive factors
•: unusual weather
•: changes in federal or state legislation
•: regulation
•: the other risk factors listed from time to time by the utility subsidiaries of Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to this Report on Form 10-K for the year ended Dec. 31, 2000.

NSP-Minnesota's Management's Discussion and Analysis

Results of Operations

NSP-Minnesota's net income was approximately $111.2 million for 2000, compared with approximately $159.0 million for the 1999.

Special Charges

During 2000, NSP-Minnesota expensed pretax special charges totaling approximately $72.1 million. The pretax charges included expenses related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE and pretax charges pertaining to incremental costs of transition and integration activities associated with the merger. For more information, see Note 2 to the Financial Statements under Item 8.

Electric Utility Margins

The following table details the change in electric revenue and margin. Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel clause cost recovery mechanisms for retail customers in several states and the ability to vary wholesale prices with changing market conditions, most fluctuations in energy costs do not affect electric margin. However, the fuel clause cost recovery in the Minnesota, North Dakota and South Dakota jurisdictions does not allow for complete recovery of all variable production expenses and, therefore, higher costs in periods of extreme temperatures can result in an adverse earnings impact.

		2000		1999		1998
		(Millions of dollars)
Electric retail and firm wholesale revenue		$	2,248	$	2,136	$	2,125
Short-term wholesale revenue			164		131		119

	Total electric utility revenue		2,412		2,267		2,244
Electric retail and firm wholesale fuel and purchase power			750		714		631
Short-term wholesale fuel and purchase power			119		97		95

	Total electric utility fuel and purchase power		869		811		726
Electric retail and firm wholesale margin			1,498		1,422		1,494
Short-term wholesale margin			45		34		24

	Total electric utility margin	$	1,543	$	1,456	$	1,518

Electric revenue increased by approximately $145 million, or 6.4 percent in 2000. Electric margin increased by approximately $87 million, or 6.0 percent in 2000. Weather normalized retail sales increased by 3.5 percent in 2000, increasing retail revenue by approximately $66 million and retail margin by approximately $52 million. In addition, 1999 electric retail revenue and margin were reduced by $32 million for the disallowance of 1998 conservation incentives by the MPUC (for more information, see Note 12 to the Financial Statements). Short-term wholesale revenue increased by $33 million and margin increased by $11 million due to the expansion of NSP-Minnesota's wholesale marketing operations and favorable market conditions.

Gas Utility Margins

The following table details the change in gas revenue and margin. The cost of gas tends to vary with changing sales requirements and unit cost of gas purchases. However, due to purchased gas cost

recovery mechanisms for retail customers, fluctuations in the cost of gas have little effect on gas margin.

	2000			1999			1998
	(Millions of dollars)
Gas revenue	$	537		$	366		$	361
Cost of gas purchased and transported		(383	)		(230	)		(226	)

Gas margin	$	154		$	136		$	135

Gas revenue increased by approximately $171 million, or 46.7 percent, in 2000, primarily due to increases in the cost of gas, which is recovered in Minnesota through the purchased gas adjustment clause and more favorable temperatures. Gas margin increased by approximately $18 million, or 13.2 percent, in 2000 due to firm gas sales growth, increased interruptible sales and higher transportation revenues.

Non-Fuel Operating Expense and Other Costs

Other Operating and Maintenance Expense increased by approximately $44 million, or 6.3 percent, for 2000, compared with 1999. The increase is largely due to the timing of outages at the Prairie Island and Monticello nuclear plants and outages at the Sherco plant. The increase is also partly due to start up costs associated with the establishment of a Nuclear Management Company.

Depreciation and Amortization Expense increased by approximately $14 million, or 4.4 percent, for 2000, compared with 1999, primarily due to increased capital additions to utility plant.

Interest expense increased by approximately $22 million, or 20.5 percent, for 2000, compared with 1999, primarily due to higher interest rates.

Other income (deductions) decreased by approximately $9 million in 2000 largely due to higher costs related to carrying charges on accrued conservation incentive refunds, and to regulatory expenses for interim fuel storage.

Derivatives, Risk Management and Market Risk

NSP-Minnesota is exposed to market and credit risks in its generation, retail distribution and energy trading operations. To minimize the risk of market price and volume fluctuations, NSP-Minnesota enters into financial derivative instrument contracts to hedge purchase and sale commitments, fuel requirements and inventories of its natural gas, distillate fuel oil, electricity and coal business.

NSP-Minnesota monitors its exposure to fluctuations in interest rates and may execute swaps, forward exchange contracts or other financial derivative instruments to manage these exposures. NSP-Minnesota manages all of its market risks through various policies and procedures that allow for the use of various derivative instruments in the energy and financial markets.

Commodity Price Risk

To manage exposure to price volatility in the natural gas and electricity markets, NSP-Minnesota uses a variety of energy contracts, both financial and physical. These contracts consist mainly of commodity forward contracts and options, index or fixed price swaps and basis swaps.

NSP-Minnesota measures its open exposure to commodity price changes using the Value-at-Risk (VaR) methodology. VaR expresses the potential loss in fair value of all open forward contract and option positions over a particular period of time, with a given confidence interval under normal market conditions. NSP-Minnesota utilizes the variance/covariance approach in calculating VaR, which assumes

that all price returns/profitability are normally and independently distributed. The model employs a 95 percent confidence interval level based on historical price movement, normal price distribution and a holding period of 21 days.

As of Dec. 31, 2000, the calculated VaR for NSP-Minnesota's regulated wholesale operations were (in millions of dollars):

Year Ended Dec. 31, 2000		Average			High			Low
$1.40		$	0.73		$	4.70		$	0.01

NSP-Minnesota does not use VaR to measure the commodity risk inherent in its regulated generation and retail sales operations. NSP-Minnesota has limited exposure to commodity risk due to fuel-cost recovery adjustment mechanisms.

Interest Rate Risk

NSP-Minnesota has both long-term and short-term debt instruments that subject NSP-Minnesota to the risk of loss associated with movements in market interest rates. This risk is limited for NSP-Minnesota, primarily due to cost-based rate regulation. In the future, management anticipates utilizing financial instruments to manage its exposure to changes in interest rates. These instruments may include interest rate swaps, caps, collars, exchange-traded futures contracts and put or call options on U.S. Treasury securities.

At Dec. 31, 2000, a 100-basis point change in the benchmark rate on NSP-Minnesota's variable debt would impact net income by approximately $6.4 million.

Credit Risk

In addition to the risks discussed previously, NSP-Minnesota is exposed to credit risk in its risk management activities. Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations. NSP-Minnesota maintains credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.

NSP-Minnesota conducts standard credit reviews for all of its counterparties. NSP-Minnesota employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees and standardized master netting agreements that allow for offsetting of positive and negative exposures. The credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

NSP-Wisconsin's Management's Discussion and Analysis

Results of Operations

NSP-Wisconsin's net income was $30.3 million for 2000, compared with $36.4 million for 1999.

Special Charges

During 2000, NSP-Wisconsin expensed pretax special charges totaling approximately $12.8 million. The pretax charges included expenses related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE and pretax charges pertaining to incremental costs of transition and integration activities associated with the merger. For more information, see Note 2 to the Financial Statements under Item 8.

Electric Utility Margins

The following table details the change in electric revenue and margin. Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Wisconsin does not have an automatic retail electric fuel adjustment clause. Instead, it has a procedure which compares actual monthly and anticipated annual fuel costs with those costs that were included in the latest retail electric rates approved by the PSCW. If the comparison results in a difference outside a certain range, the PSCW may hold hearings limited to fuel costs and revise rates. Therefore, the fuel clause cost recovery in Wisconsin does not allow for complete recovery of all variable production expenses and higher costs, particularly in periods of extreme temperatures, and can result in an adverse earnings impact.

	2000			1999			1998
	(Millions of dollars)
Electric revenue	$	424		$	412		$	398
Electric fuel and purchased power		(210	)		(202	)		(201	)

Electric margin	$	214		$	210		$	197

Electric revenue increased by approximately $12 million, or 2.9 percent, and electric margin increased by approximately $4 million, or 1.9 percent, in 2000, due largely to higher sales resulting from sales growth and more favorable temperatures. Weather normalized sales increased by 2.4 percent in 2000. These margin increases were partially offset by increased purchased and interchange power costs reducing margin by approximately $5 million.

Gas Utility Margins

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

	2000			1999			1998
	(Millions of dollars)
Gas revenue	$	110		$	82		$	79
Cost of gas purchased and transported		(82	)		(56	)		(53	)

Gas margin	$	28		$	26		$	26

Gas revenue for 2000 increased by approximately $28 million, or 34.1 percent, in 2000 compared with 1999, largely due to higher cost of gas and higher sales resulting from sales growth and more

favorable temperatures. Gas margin for 2000 increased by approximately $2 million, or 7.7 percent, compared with 1999, largely due sales growth and more favorable temperatures.

Non-Fuel Operating Expense and Other Costs

Other Operation and Maintenance Expense increased by approximately $5.4 million, or 5.4 percent, for 2000, compared with 1999. The increase is largely due to the write-off of software costs, increases in the reserve for uncollectible accounts, increased employee benefit costs and increased authorized demand side management partially offset by decreased expenses related to storm damage.

Interest expense increased by approximately $0.7 million, or 3.9 percent, for 2000, compared with 1999, primarily due to higher short-term interest rates and interests on new long-term debt issued in 2000.

Depreciation and Amortization Expense was $1.6 million, or 3.8 percent lower in 2000 compared with 1999. The reduction was primarily the result of changes in depreciation rates, changes in depreciation method to remaining life technique and some fully depreciated plant, all effective January 2000.

Market Risk

NSP-Wisconsin does not enter into financial derivative instrument contracts or forward exchange contracts. NSP-Wisconsin has limited exposure to commodity risk due to regulatory based cost recovery.

In addition, with the exception of short-term borrowings, NSP-Wisconsin does not have variable interest rates, therefore there is limited interest rate risk.

NSP-Wisconsin maintains credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.

PSCo's Management's Discussion and Analysis

Results of Operations

PSCo's net income was $196.1 million for 2000, compared with $204.3 million for 1999.

Special Charges

PSCo's earnings for 2000 were reduced by special charges related to the merger to form Xcel Energy. During 2000, PSCo expensed pretax special charges of $78.8 million. The pretax charges included expenses related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE and pretax charges pertaining to incremental costs of transition and integration activities associated with the merger. For more information, see Note 2 to the Financial Statements under Item 8.

Electric Utility Margins

The following table details the changes in electric utility revenue and margin. Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. PSCo has adjustment clauses that allow certain costs to be passed through to retail customers. The ICA allows for an equal sharing among customers and shareholders of certain fuel and energy cost increases and decreases. The QFCCA provides for recovery of purchased capacity costs from certain qualifying facilities projects not otherwise reflected in base electric rates. Therefore, the fuel clause cost recovery does not allow for complete recovery of all variable production expenses and higher costs can result in an adverse earnings impact.

		2000		1999		1998
		(Millions of dollars)
Electric retail and firm wholesale revenue		$	1,603	$	1,506	$	1,488
Short-term wholesale revenue			411		52		148

	Total electric utility revenue		2,014		1,558		1,636
Electric retail and firm wholesale fuel and purchase power			799		674		659
Short-term wholesale fuel and purchase power			330		32		143

	Total electric utility fuel and purchase power		1,129		706		802
Electric retail and firm wholesale margin			804		832		829
Short-term wholesale margin			81		20		5

	Total electric utility margin	$	885	$	852	$	834

Electric revenue increased by approximately $456 million, or 29.3 percent, in 2000. Electric margin increased by approximately $33 million, or 3.9 percent, in 2000. Weather normalized retail sales increased by 4.4 percent in 2000, increasing retail revenue by approximately $60 million and retail margin by approximately $29 million. More favorable temperatures during 2000 increased retail revenue by approximately $38 million and retail margin by approximately $18 million. These retail margin increases were partially offset by regulatory adjustment, relating to system reliability and availability in Colorado. Short-term wholesale revenue increased by $359 million and margin increased by $61 million due to the expansion of PSCo's wholesale marketing area and favorable market conditions.

Gas Utility Margins

The following table details the changes in gas utility revenue and margin. The cost of gas tends to vary with changing sales requirements and the unit cost of gas purchases. PSCo has in place a Gas Cost Adjustment mechanism for natural gas sales, which recognizes the majority of the effects of changes in

the cost of gas purchases for resale and adjusts revenues to reflect such changes in costs on a timely basis. Therefore, fluctuations in the cost of gas have little effect on gas margins.

	2000			1999			1998
	(Millions of dollars)
Gas revenue	$	787		$	658		$	640
Cost of gas sold and transported		(487	)		(395	)		(381	)

Gas margin	$	300		$	263		$	259

Gas revenue increased by approximately $129 million, or 19.6 percent, in 2000, primarily due to increases in the cost of natural gas, which are largely recovered through adjustment clauses. Gas margin increased by approximately $37 million, or 14.1 percent, in 2000. More favorable temperatures during 2000 increased gas revenue by $57 million and gas margins by $23 million.

Electric Trading Margins

Trading revenues and costs of goods sold do not include the revenue and production costs associated with energy produced from generation assets. The following table details the changes in electric trading revenue and margin.

	2000			1999			1998
	(Millions of dollars)
Trading revenue	$	813		$	482		$	0
Trading cost of goods sold		(784	)		(479	)		(0	)

Trading margin	$	29		$	3		$	0

Trading revenue increased by approximately $331 million and trading margin increased by approximately $26 million in 2000. The increase in trading revenue and margin is a result of the expansion of PSCo's electric trading.

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expense for 2000 increased by approximately $8.8 million, or 2.3 percent, compared with 1999. The increase is largely due to bad debt reserves for the trading operations.

Depreciation and Amortization Expense for 2000 increased $16.3 million, or 8.4 percent, compared with 1999, primarily due to increased additions to utility plant.

Interest charges and financing costs increased $5.1 million, or 3.3 percent, in 2000. The increase is primarily attributable to the issuance of the $200 million of 6.875 percent Series A Notes in July 1999.

Derivatives, Risk Management and Market Risk

PSCo is exposed to market and credit risks in its generation, retail distribution and energy trading operations. To minimize the risk of market price and volume fluctuations, PSCo enters into financial derivative instrument contracts to hedge purchase and sale commitments, fuel requirements and inventories of its natural gas, distillate fuel oil, electricity and coal business, and emission allowances. The primary objective of PSCo's trading operations is to maximize asset value, while minimizing the related exposure to changes in commodity prices and counterparty default. These operations include wholesale power marketing and trading activities.

PSCo monitors its exposure to fluctuations in interest rates and may execute swaps, forward exchange contracts or other financial derivative instruments to manage these exposures. PSCo manages

all of its market risks through various policies and procedures that allow for the use of various derivative instruments in the energy and financial markets.

Commodity Price Risk

PSCo has continued to develop and expand its power marketing and trading activities and management expects to continue the growth of these activities during 2001. As a result, PSCo's exposure to changes in commodity prices may increase and earnings may experience volatility. To manage exposure to price volatility in the natural gas and electricity markets, PSCo uses a variety of energy contracts, both financial and physical. These contracts consist mainly of commodity forward contracts and options, index or fixed price swaps and basis swaps.

PSCo measures its open exposure to commodity price changes using the Value-at-Risk (VaR) methodology. VaR expresses the potential loss in fair value of all open forward contract and option positions over a particular period of time, with a given confidence interval under normal market conditions. PSCo utilizes the variance/covariance approach in calculating VaR, which assumes that all price returns/profitability are normally and independently distributed. The model employs a 95 percent confidence interval level based on historical price movement, normal price distribution and a holding period of 21 days.

As of Dec. 31, 2000, the calculated VaR for PSCo's regulated trading operations were (in millions of dollars):

Year Ended Dec. 31, 2000		Average			High			Low
$4.62		$	1.42		$	7.23		$	0.08

PSCo does not use VaR to measure the commodity risk inherent in its regulated generation and retail sales operations. PSCo has limited exposure to commodity risk due to fuel-cost recovery adjustment mechanisms.

In Colorado, a sharing mechanism between shareholders and customers exists which utilizes an established benchmark per unit cost for energy. Consequently, changes in any eligible costs collected under this benchmark approach, has a resultant market risk. The impact of eligible production and fuel cost volatility on Colorado jurisdiction retail business shows that as of Dec. 31, 2000, a 15-percent increase in eligible production and fuel costs would result in a loss in income from these contracts of approximately $18 million. Conversely, a 15-percent decrease in eligible production and fuel costs would result in a positive income gain from these contracts of approximately $39 million. This analysis assumes that there were no changes in energy consumption, customer growth, operations, energy dispatch, regulatory guidelines, or market conditions. This analysis is solely focused on the change in fuel eligible production and fuel costs and the resultant market risk due to the ICA mechanism in the state of Colorado. The market risk caused by change in eligible production and fuel costs, under the ICA mechanism, is affected by margins earned on certain trading activities. Generally, these margins serve to mitigate the impact of market risk on PSCo and the customer.

Interest Rate Risk

PSCo has both long-term and short-term debt instruments that subject PSCo to the risk of loss associated with movements in market interest rates. This risk is limited primarily due to cost-based rate regulation. In the future, management anticipates utilizing financial instruments to manage its exposure to changes in interest rates. These instruments may include interest rate swaps, caps, collars, exchange-traded futures contracts and put or call options on U.S. Treasury securities.

At Dec. 31, 2000, a 100-basis point change in the benchmark rate on PSCo's variable debt would impact net income by approximately $3.3 million.

Credit Risk

In addition to the risks discussed previously, PSCo is exposed to credit risk in its risk management activities. Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations. As PSCo continues to expand its power marketing and trading activities, its exposure to credit risk and counterparty default may increase. PSCo maintains credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.

PSCo conducts standard credit reviews for all of its counterparties. PSCo employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees and standardized master netting agreements that allow for offsetting of positive and negative exposures. The credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

SPS' Management's Discussion and Analysis

Results of Operations

SPS' net income was $69.5 million for 2000, compared with $102.7 million for 1999.

Extraordinary Items

SPS' earnings for 2000 were reduced by two extraordinary items related to the discontinuation of regulatory accounting for SPS' generation business. During the second quarter of 2000, SPS wrote off its generation-related regulatory assets and other deferred costs for an extraordinary charge of approximately $19 million before taxes, or $13.7 million after tax. During the third quarter of 2000, SPS recorded an additional extraordinary charge of $8.2 million before tax, or $5.3 million after tax, related to the tender offer/defeasance of approximately $295 million of First Mortgage bonds. For more information on SPS restructuring see Note 10 to the Financial Statements under Item 8.

Special Charges

SPS' earnings for 2000 were reduced by special charges related to the merger to form Xcel Energy. During the third and fourth quarter of 2000, SPS expensed pretax special charges of $24.3 million. The pretax charges included expenses related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE and pretax charges pertaining to incremental costs of transition and integration activities associated with the merger. For more information, see Note 2 to the Financial Statements under Item 8.

Electric Utility Margins

The following table details the change in electric revenue and margin. Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Fuel and purchased power costs are recoverable in SPS' Texas jurisdiction through a fixed fuel factor, which is included in rates. In the New Mexico retail jurisdiction, fuel and purchased energy costs are adjusted through a fuel clause and a fixed annual factor. In all other jurisdictions, SPS currently recovers substantially all increases and refunds substantially all decreases in fuel and purchased power costs pursuant to monthly adjustment clauses. Due to these fuel clause cost recovery mechanisms for retail customers and the ability to vary wholesale prices with changing market conditions, most fluctuations in energy costs do not affect electric margin. However, the fuel clause cost

recovery does not allow for complete recovery of all variable production expenses and, therefore, higher costs can result in an adverse earnings impact.

			2000		1999		1998
			(Millions of dollars)
Electric retail and firm wholesale revenue			$	981	$	858	$	872
Short-term wholesale revenue				99		68		79

	Total electric utility revenue			1,080		926		951
Electric retail and firm wholesale fuel and purchase power				480		384		381
Short-term wholesale fuel and purchase power				93		64		74

	Total electric utility fuel and purchase power			573		448		455
Electric retail and firm wholesale margin				501		474		491
Short-term wholesale margin				6		4		5

		Total electric utility margin	$	507	$	478	$	496

Electric revenue and margin for 2000 increased, compared with 1999, largely due to sales growth and the effects of warmer and drier summer and early fall weather. The year 2000 was warmer than the corresponding period in 1999, resulting in higher retail and wholesale sales. Weather normalized retail sales increased by 3.1 percent in 2000, increasing retail revenue by approximately $20 million and retail margin by approximately $10 million. More favorable temperatures during 2000 increased retail revenue by approximately $3 million and retail margin by approximately $2 million.

Non-Fuel Operating Expense and Other Costs

Other Operation and Maintenance Expense increased by approximately $18.4 million, or 13.3 percent, for 2000, compared with 1999, primarily due to increases in steam generation expenses, transmission expenses, and customer expenses.

Depreciation and Amortization Expense increased by approximately $2.6 million, or 3.4 percent, for 2000, compared with 1999, primarily due to increased capital additions to utility plant.

Interest charges and financing costs increased by approximately $1.1 million, or 1.7 percent, for 2000, compared with 1999, primarily due to the increase in short-term debt associated with the tender offer/defeasance of SPS' First Mortgage bonds.

Market Risk

SPS has both long-term and short-term debt instruments that subject SPS to the risk of loss associated with movements in market interest rates. This risk is limited for SPS, primarily due to cost-based rate regulation. In the future, management anticipates utilizing financial instruments to manage its exposure to changes in interest rates. These instruments may include interest rate swaps, caps, collars, exchange-traded futures contracts and put or call options on U.S. Treasury securities.

At Dec. 31, 2000, a 100-basis point change in the benchmark rate on SPS's variable debt would impact net income by approximately $3.9 million.

SPS does not enter into financial derivative instrument contracts or forward exchange contracts. SPS has limited exposure to commodity risk due to regulatory based cost recovery.

SPS maintains credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.

ITEM 7A—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Management's Discussion and Analysis under Item 7, incorporated by reference.

ITEM 8—FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA

Report of Independent Public Accountants—NSP-Minnesota

To Northern States Power Company—Minnesota:

We have audited the accompanying consolidated balance sheet and statement of capitalization of Northern States Power Company—Minnesota (a Minnesota corporation) and subsidiaries as of Dec. 31, 2000, and the related consolidated statements of income, stockholder's equity and cash flows for the year then ended. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northern States Power Company—Minnesota and its subsidiaries as of Dec. 31, 2000, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States.

Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index of the consolidated financial statements is presented for purposes of complying with the Securities and Exchange Commission's rules and is not a required part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audit of the basic financial statements and, in our opinion, fairly states, in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

ARTHUR ANDERSEN LLP

Minneapolis, Minnesota,
March 2, 2001

Report of Independent Public Accountants—NSP-Minnesota

To the Board of Directors and Shareholder of Northern States Power Company
(a wholly-owned subsidiary of Xcel Energy Inc.):

In our opinion, the accompanying consolidated balance sheets and statements of capitalization and the related consolidated statements of income, of divisional equity and of cash flows present fairly, in all material respects, the financial position of Northern States Power Company, a Minnesota corporation (a wholly-owned subsidiary of Xcel Energy Inc.), and its subsidiaries at December 31, 1999 and 1998, and the results of their operations and their cash flows for the years ended December 31, 1999 and 1998 in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.

PricewaterhouseCoopers LLP
Minneapolis, Minnesota
January 31, 2000, except as to Note 1,
which is as of August 18, 2000

Report of Independent Public Accountants—NSP-Wisconsin

To Northern States Power Company—Wisconsin:

We have audited the accompanying consolidated balance sheet and statement of capitalization of Northern States Power Company—Wisconsin (a Wisconsin corporation) and subsidiaries as of Dec. 31, 2000, and the related consolidated statements of income, stockholder's equity and cash flows for the year then ended. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northern States Power Company—Wisconsin and its subsidiaries as of Dec. 31, 2000, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States.

ARTHUR ANDERSEN LLP

Minneapolis, Minnesota,
March 2, 2001

To The Shareholder of Northern States Power Company (Wisconsin):

In our opinion, the accompanying balance sheets and the related statements of income and retained earnings and of cash flows present fairly, in all material respects, the financial position of Northern States Power Company (NSP-Wisconsin), a Wisconsin corporation, at Dec. 31, 1999 and 1998, and the results of its operations and its cash flows for the years ended Dec. 31, 1999 and 1998, in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of NSP-Wisconsin's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.

PRICEWATERHOUSECOOPERS LLP
Minneapolis, Minnesota
Jan. 31, 2000

Report of Independent Public Accountants—PSCo

To Public Service Company of Colorado:

We have audited the accompanying consolidated balance sheets and statements of capitalization of Public Service Company of Colorado (a Colorado corporation) and subsidiaries as of Dec. 31, 2000 and 1999, and the related consolidated statements of income, stockholder's equity and cash flows for each of the three years in the period ended Dec. 31, 2000. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Public Service Company of Colorado and its subsidiaries as of Dec. 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended Dec. 31, 2000 in conformity with accounting principles generally accepted in the United States.

Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index of the consolidated financial statements is presented for purposes of complying with the Securities and Exchange Commission's rules and is not a required part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly states, in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

ARTHUR ANDERSEN LLP

Minneapolis, Minnesota,
March 2, 2001

Report of Independent Public Accountants—SPS

To Southwestern Public Service Company:

We have audited the accompanying balance sheets and statements of capitalization of Southwestern Public Service Company (a New Mexico corporation) as of Dec. 31, 2000 and 1999, and the related statements of income, stockholder's equity and cash flows for each of the three years in the period ended Dec. 31, 2000. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwestern Public Service Company as of Dec. 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended Dec. 31, 2000 in conformity with accounting principles generally accepted in the United States.

Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index of the financial statements is presented for purposes of complying with the Securities and Exchange Commission's rules and is not a required part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly states, in all material respects, the financial data required to be set forth there in relation to the basic financial statements taken as a whole.

ARTHUR ANDERSEN LLP

Minneapolis, Minnesota,
March 2, 2001

NSP-MINNESOTA
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars)
Year ended December 31

			2000			1999			1998
Operating revenues:
	Electric utility		$	2,411,883		$	2,267,213		$	2,243,773
	Gas utility			536,700			365,835			360,568

		Total revenue		2,948,583			2,633,048			2,604,341
Operating expenses:
	Electric fuel and purchased power			869,421			811,460			726,328
	Cost of gas sold and transported			382,596			229,913			225,956
	Other operating and maintenance expenses			742,607			698,536			725,866
	Depreciation and amortization			323,935			310,129			296,059
	Taxes (other than income taxes)			202,245			204,755			203,562
	Special charges (see Note 2)			72,095			0			0

		Total operating expenses		2,592,899			2,254,793			2,177,771

Operating income				355,684			378,255			426,570
Other income (deductions) — net				(9,884	)		(1,070	)		14,721
Interest charges and financing costs:
	Interest charges — net of amount capitalized			126,635			105,024			90,622
	Distributions on redeemable preferred securities of subsidiary trust			15,750			15,750			15,750

		Total interest charges and financing costs		142,385			120,774			106,372

Income before income taxes				203,415			256,411			334,919
Income taxes				92,191			97,431			124,713

Net income			$	111,224		$	158,980		$	210,206

The Notes to Consolidated Financial Statements are an integral
part of the Statements of Income.

NSP-Minnesota
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
Year ended December 31

				2000			1999			1998
Operating activities:
	Net income			$	111,224		$	158,980		$	210,206
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			340,868			327,415			313,485
		Nuclear fuel amortization			44,591			50,056			43,816
		Deferred income taxes			1,341			(9,729	)		(12,841	)
		Amortization of investment tax credits			(9,017	)		(8,324	)		(9,023	)
		Allowance for equity funds used during construction			4,176			300			(8,106	)
		Conservation incentive accrual adjustment — noncash			19,248			71,348			0
		Change in accounts receivable			16,016			(18,109	)		(41,596	)
		Change in inventories			(2,447	)		(7,672	)		(3,547	)
		Change in other current assets			(64,324	)		(30,591	)		86
		Change in accounts payable			123,059			(28,385	)		32,560
		Change in other current liabilities			(30,407	)		12,367			22,720
		Change in other assets and liabilities			(62,063	)		38,893			23,810

			Net cash provided by operating activities		492,265			556,549			571,570
Investing activities:
	Capital/construction expenditures				(391,727	)		(355,788	)		(335,673	)
	Allowance for equity funds used during construction				(4,176	)		(300	)		8,106
	Investments in external decommissioning fund				(48,967	)		(39,183	)		(41,360	)
	Other investments — net				454			(6,002	)		(1,869	)

			Net cash used in investing activities		(444,416	)		(401,273	)		(370,796	)
Financing activities:
	Short-term borrowings — net				(61,005	)		305,920			(24,079	)
	Proceeds from issuance of long-term debt — net				76,127			264,829			251,032
	Repayment of long-term debt, including reacquisition premiums				(180,730	)		(224,283	)		(109,669	)
	Capital contributions from affiliates				358,632			0			0
	Cash distributions to parent				(240,291	)		(510,523	)		(318,909	)

			Net cash used in financing activities		(47,267	)		(164,057	)		(201,625	)

	Net increase (decrease) in cash and cash equivalents				582			(8,781	)		(851	)
	Cash and cash equivalents at beginning of period				11,344			20,125			20,976

	Cash and cash equivalents at end of period			$	11,926		$	11,344		$	20,125

Supplemental disclosure of cash flow information
	Cash paid for interest (net of amount capitalized)			$	128,530		$	100,145		$	88,194
	Cash paid for income taxes (net of refunds received)			$	105,720		$	85,243		$	57,595

The Notes to Consolidated Financial Statements are an integral
part of the Statements of Cash Flow.

NSP-MINNESOTA
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)

			Dec. 31 2000			Dec. 31 1999
ASSETS
Current assets:
	Cash and cash equivalents		$	11,926		$	11,344
	Accounts receivable—net of allowance for bad debts of $4,952 and $5,503, respectively			281,611			236,456
	Accounts receivable from affiliates			49,699			110,870
	Accrued unbilled revenues			194,547			122,493
	Materials and supplies inventories at average cost			103,863			101,678
	Fuel and gas inventories at average cost			51,775			51,514
	Prepayments and other			44,843			50,141

		Total current assets		738,264			684,496

Property, plant and equipment, at cost:
	Electric utility			6,388,697			6,320,214
	Gas utility			666,078			629,158
	Other and construction work in progress			531,678			441,141

		Total property, plant and equipment		7,586,453			7,390,513
	Less: accumulated depreciation			(4,017,813	)		(3,855,225	)
	Nuclear fuel—net of accumulated amortization of $967,928 and $923,336, respectively			86,499			102,727

		Net property, plant and equipment		3,655,139			3,638,015

Other assets:
	Nuclear decommissioning fund investments			563,812			517,129
	Other investments			24,892			25,341
	Regulatory assets			226,547			208,176
	Deferred charges and other			151,334			94,549

		Total other assets		966,585			845,195

		Total Assets	$	5,359,988		$	5,167,706

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	303,773		$	255,718
	Short-term debt			359,189			420,193
	Accounts payable			303,053			203,684
	Accounts payable to affiliates			30,965			7,268
	Taxes accrued			130,870			162,748
	Other			162,683			177,541

		Total current liabilities		1,290,533			1,227,152

Deferred credits and other liabilities:
	Deferred income taxes			678,849			681,431
	Deferred investment tax credits			91,088			100,105
	Regulatory liabilities			496,313			439,717
	Benefit obligations and other			146,541			146,620

		Total deferred credits and other liabilities		1,412,791			1,367,873

Long-term debt				1,048,995			1,186,586
Mandatorily redeemable preferred securities of subsidiary trust				200,000			200,000
Common stock and paid-in capital				479,397			145,613
Retained earnings				952,889			1,052,088
Leveraged shares held by ESOP at cost				(24,617	)		(11,606	)

		Total common stockholder's equity		1,407,669			1,186,095
Commitments and contingencies (see Note 12)

		Total Liabilities and Equity	$	5,359,988		$	5,167,706

The Notes to Consolidated Financial Statements are an integral
part of the Balance Sheets.

NSP-MINNESOTA
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
(Thousands of Dollars)

	Common Stock and Paid in Capital			Retained Earnings			Leveraged ESOP			Total Common Stockholder's Equity
Balance at Dec. 31, 1997	$	599,599		$	1,058,602		$	(10,533	)	$	1,647,668

Net income — comprehensive income					210,206						210,206
Capital distributions to parent		(137,519	)		(181,413	)					(318,932	)
Loan to ESOP to purchase shares								(15,000	)		(15,000	)
Repayment of ESOP loan								7,030			7,030

Balance at Dec. 31, 1998	$	462,080		$	1,087,395		$	(18,503	)	$	1,530,972

Net income — comprehensive income					158,980						158,980
Capital distributions to parent		(316,467	)		(198,885	)					(515,352	)
Pooling of interests business combination					4,598						4,598
Repayment of ESOP loan								6,897			6,897

Balance at Dec. 31, 1999	$	145,613		$	1,052,088		$	(11,606	)	$	1,186,095

Net income — comprehensive income					111,224						111,224
Capital distributions to parent		(16,216	)		(210,423	)					(226,639	)
Capital contribution from parent		350,000									350,000
Loan to ESOP to purchase shares								(20,000	)		(20,000	)
Repayment of ESOP loan								6,989			6,989

Balance at Dec. 31, 2000	$	479,397		$	952,889		$	(24,617	)	$	1,407,669

The Notes to Consolidated Financial Statements are an integral
part of the Statements of Stockholder's Equity.

NSP-MINNESOTA
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Thousands of Dollars)

			Dec. 31
			2000			1999
Long-Term Debt
First Mortgage Bonds, Series due:
	Dec. 1, 2000-2006, 3.50-4.10%		$	13,230	(a)	$	15,170	(a)
	Dec. 1, 2000, 5.75%			0			100,000
	Oct. 1, 2001, 7.875%			150,000			150,000
	March 1, 2003, 5.875%			100,000			100,000
	April 1, 2003, 6.375%			80,000			80,000
	Dec. 1, 2005, 6.125%			70,000			70,000
	April 1, 2007, 6.80%			0			60,000	(b)
	March 1, 2011, variable rate, 5.05% at Dec. 31, 2000 and 5.75% at Dec. 31, 1999			13,700	(b)		13,700	(b)
	March 1, 2019, variable rate, 4.25% at Dec. 31, 2000 and 3.7% at Dec. 31, 1999			27,900	(b)		27,900	(b)
	Sept. 1, 2019, variable rate 4.36% and 4.61% at Dec. 31, 2000 and 3.71% at Dec. 31, 1999			100,000	(b)		100,000	(b)
	July 1, 2025, 7.125%			250,000			250,000
	March 1, 2028, 6.5%			150,000			150,000
Guaranty Agreements, Series due: Feb. 1, 1999 — May 1, 2003, 5.375% — 7.40%				29,950	(b)		30,650	(b)
NSP-Minnesota Senior Notes Due Aug. 1, 2009, 6.875%				250,000			250,000
City of Becker Pollution Control Revenue Bonds — Series due Dec. 1, 2005, 7.25%				0			9,000	(b)
City of Becker Pollution Control Revenue Bonds — Series due April 1, 2030, 5.1% at Dec. 31, 2000				69,000	(b)		0
Anoka County Resource Recovery Bond — Series due Dec. 1, 2000—2008, 4.05% — 5.0%				17,990			19,615	(a)
Employee Stock Ownership Plan Bank Loans due 2000-2007, variable rate				24,617			11,606
Other				11,894			11,267
Unamortized discount-net				(5,513	)		(6,604	)

		Total		1,352,768			1,442,304
Less redeemable bonds classified as current (See Note 4)				141,600			141,600
Less current maturities				162,173			114,118

		Total NSP-Minnesota long-term debt	$	1,048,995		$	1,186,586

Mandatorily Redeemable Preferred Securities of Subsidiary Trust holding as its sole asset junior subordinated deferrable debentures of NSP-Minnesota, (see Note 6)			$	200,000		$	200,000

Common Stockholder's Equity
	Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares		$	10		$	10
	Premium on common stock			479,387			145,603
	Retained earnings			952,889			1,052,088
	Leveraged ESOP			(24,617	)		(11,606	)

		Total common stockholder's equity	$	1,407,669		$	1,186,095

(a) Resource recovery financing

(b) Pollution control financing

The Notes to Consolidated Financial Statements are an integral
part of the Statements of Capitalization.

NSP-WISCONSIN
STATEMENTS OF INCOME
(Thousands of Dollars)
Year ended December 31

			2000		1999		1998
Operating revenues:
	Electric utility		$	424,477	$	411,532	$	398,497
	Gas utility			110,023		82,375		78,845

		Total revenue		534,500		493,907		477,342
Operating expenses:
	Electric fuel and purchased power			210,088		202,482		201,374
	Cost of gas sold and transported			81,843		55,534		53,067
	Other operating and maintenance expenses			104,559		99,156		98,820
	Depreciation and amortization			40,502		42,117		39,135
	Taxes (other than income taxes)			15,350		14,725		14,507
	Special charges (see Note 2)			12,848		0		0

		Total operating expenses		465,190		414,014		406,903

Operating income				69,310		79,893		70,439
Other income (deductions) — net				931		305		903
Interest charges				19,255		18,530		18,679

Income before income taxes				50,986		61,668		52,663
Income taxes				20,690		25,302		20,468

Net income			$	30,296	$	36,366	$	32,195

The Notes to Financial Statements are an integral
part of the Statements of Income.

NSP-Wisconsin
STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
Year ended December 31

				2000			1999			1998
Operating activities:
	Net income			$	30,296		$	36,366		$	32,195
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			41,473			43,044			40,059
		Deferred income taxes			1,868			3,695			5,405
		Amortization of investment tax credits			(827	)		(838	)		(859	)
		Allowance for equity funds used during construction			(200	)		(271	)		(394	)
		Undistributed equity in earnings of unconsolidated affiliates			(411	)		(409	)		(3	)
		Change in accounts receivable			(16,127	)		(2,573	)		3,448
		Change in inventories			(31	)		4,482			(1,243	)
		Change in other current assets			(10,235	)		(361	)		(5,949	)
		Change in accounts payable			24,265			6,144			596
		Change in other current liabilities			4,621			(1,087	)		1,760
		Change in other assets and liabilities			(3,599	)		(3,244	)		6,280

			Net cash provided by operating activities		71,093			84,948			81,295
Investing activities:
	Capital/construction expenditures				(88,624	)		(82,508	)		(66,109	)
	Allowance for equity funds used during construction				200			271			394
	Other investments — net				(161	)		(614	)		347

			Net cash used in investing activities		(88,585	)		(82,851	)		(65,368	)
Financing activities:
	Short-term borrowings — net				(64,900	)		24,900			10,400
	Proceeds from issuance of long-term debt — net				79,399			0			(167	)
	Issuance of common stock to parent				29,977			0			65
	Dividends paid to parent				(27,004	)		(26,997	)		(26,205	)

			Net cash provided by (used in) financing activities		17,472			(2,097	)		(15,907	)

	Net increase (decrease) in cash and cash equivalents				(20	)		0			20
	Cash and cash equivalents at beginning of period				51			51			31

	Cash and cash equivalents at end of period			$	31		$	51		$	51

Supplemental disclosure of cash flow information
	Cash paid for interest (net of amount capitalized)			$	17,175		$	17,565		$	17,345
	Cash paid for income taxes (net of refunds received)			$	22,665		$	24,838		$	10,824

The Notes to Financial Statements are an integral
part of the Statements of Cash Flow.

NSP-WISCONSIN
BALANCE SHEETS
(Thousands of Dollars)

			Dec. 31 2000			Dec. 31 1999
ASSETS
Current assets:
	Cash and cash equivalents		$	31		$	51
	Accounts receivable — net of allowance for bad debts of $798 and $943, respectively			53,447			37,320
	Accrued unbilled revenues			29,113			21,768
	Materials and supplies inventories at average cost			6,544			7,068
	Fuel and gas inventories at average cost			8,021			7,465
	Prepayments and other			15,966			13,076

		Total current assets		113,122			86,748

Property, plant and equipment, at cost:
	Electric utility			1,066,446			990,527
	Gas utility			123,979			117,202
	Other and construction work in progress			124,581			132,591

		Total property, plant and equipment		1,315,006			1,240,320
	Less: accumulated depreciation			(515,745	)		(487,549	)

		Net property, plant and equipment		799,261			752,771

Other assets:
	Other investments			9,867			9,295
	Regulatory assets			38,536			39,252
	Deferred charges and other			25,289			19,037

		Total other assets		73,692			67,584

		Total Assets	$	986,075		$	907,103

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	34		$	0
	Short-term debt — notes payable to affiliate			15,900			80,800
	Accounts payable			37,981			20,004
	Accounts payable to affiliates			25,202			21,404
	Taxes accrued			0			829
	Other			19,951			14,502

		Total current liabilities		99,068			137,539

Deferred credits and other liabilities:
	Deferred income taxes			115,682			111,772
	Deferred investment tax credits			16,451			17,281
	Regulatory liabilities			18,818			21,726
	Benefit obligations and other			32,787			29,835

		Total deferred credits and other liabilities		183,738			180,614

Long-term debt				313,000			231,950
Common stock and paid-in capital				126,718			96,741
Retained earnings				263,551			260,259

		Total common stockholder's equity		390,269			357,000
Commitments and contingencies (see Note 12)

		Total Liabilities and Equity	$	986,075		$	907,103

The Notes to Financial Statements are an integral
part of the Balance Sheets.

NSP-WISCONSIN
STATEMENTS OF STOCKHOLDER'S EQUITY
(Thousands of Dollars)

		Par Value		Premium		Retained Earnings			Total Stockholder's Equity
Balance at Dec. 31, 1997		$	86,200	$	10,461	$	244,171		$	340,832

Net income — comprehensive income							32,195			32,195
Dividends declared:
	Common stock to parent						(26,205	)		(26,205	)
Business combination					80		729			809

Balance at Dec. 31, 1998		$	86,200	$	10,541	$	250,890		$	347,631

Net income — comprehensive income							36,366			36,366
Dividends declared:
	Common stock to parent						(26,997	)		(26,997	)

Balance at Dec. 31, 1999		$	86,200	$	10,541	$	260,259		$	357,000

Net income — comprehensive income							30,296			30,296
Dividends declared:
	Common stock to parent						(27,004	)		(27,004	)
Issuance of common stock to parent			7,100		22,877					29,977

Balance at Dec. 31, 2000		$	93,300	$	33,418	$	263,551		$	390,269

The Notes to Consolidated Financial Statements are an integral
part of the Statements of Stockholder's Equity.

NSP-WISCONSIN
STATEMENTS OF CAPITALIZATION
(Thousands of Dollars)

			Dec. 31
			2000			1999
Long-Term Debt
First Mortgage Bonds Series due:
	Oct. 1, 2003, 5.75%		$	40,000		$	40,000
	March 1, 2023, 7.25%			110,000			110,000
	Dec. 1, 2026, 7.375%			65,000			65,000
City of La Crosse Resource Recovery Bond — Series due Nov. 1, 2021, 6%				18,600	(a)		18,600	(a)
Fort McCoy System Acquisition — due Oct. 31, 2030, 7%				996			0
Senior Notes — due Oct. 1, 2008, 7.64%				80,000			0
Unamortized discount				(1,562	)		(1,650	)

		Total		313,034			231,950
Less current maturities				34			0

		Total NSP-Wisconsin long-term debt	$	313,000		$	231,950

Common Stockholder's Equity
	Common stock — authorized 1,000,000 shares of $100 par value; outstanding shares: 2000, 933,000; 1999, 862,000		$	93,300		$	86,200
	Premium on common stock			33,418			10,541
	Retained earnings			263,551			260,259

		Total common stockholder's equity	$	390,269		$	357,000

(a) Resource recovery financing

The Notes to Financial Statements are an integral
part of the Statements of Capitalization.

PUBLIC SERVICE COMPANY OF COLORADO
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars)
Year ended December 31

			2000		1999		1998
Operating revenues:
	Electric utility		$	2,013,732	$	1,558,375	$	1,635,573
	Electric trading			813,449		482,008		0
	Gas utility			787,110		657,822		640,064
	Steam utility			10,845		8,045		8,348

		Total revenue		3,625,136		2,706,250		2,283,985
Operating expenses:
	Electric fuel and purchased power			1,128,693		706,476		801,821
	Electric trading costs			783,956		479,331		0
	Cost of gas sold and transported			486,800		394,678		380,554
	Steam costs			6,177		4,437		4,593
	Other operating and maintenance expenses			399,304		390,464		398,699
	Depreciation and amortization			210,704		194,365		180,913
	Taxes (other than income taxes)			77,885		84,456		83,994
	Special charges (see Note 2)			78,779		0		0

		Total operating expenses		3,172,298		2,254,207		1,850,574

Operating income				452,838		452,043		433,411
Other income (deductions) — net				7,351		4,970		6,500
Interest charges and financing costs:
	Interest charges — net of amount capitalized			146,091		140,974		128,603
	Distributions on redeemable preferred securities of subsidiary trust			15,200		15,200		9,711

		Total interest charges and financing costs		161,291		156,174		138,314

Income before income taxes				298,898		300,839		301,597
Income taxes				102,770		96,574		101,494

Net income				196,128		204,265		200,103
Dividend requirements and redemption premiums on preferred stock				0		0		5,332

Earnings available for common shareholders			$	196,128	$	204,265	$	194,771

The Notes to Consolidated Financial Statements are an integral
part of the Statements of Income.

PUBLIC SERVICE COMPANY OF COLORADO
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
Year ended December 31

				2000			1999			1998
Operating activities:
	Net income			$	196,128		$	204,265		$	200,103
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			216,212			202,634			186,620
		Deferred income taxes			(35,234	)		15,817			7,092
		Amortization of investment tax credits			(5,481	)		(5,173	)		(4,896	)
		Equity in earnings of Yorkshire Power			0			0			(3,446	)
		Change in accounts receivable			(29,653	)		(25,687	)		21,540
		Change in inventories			36,480			(21,298	)		(6,553	)
		Change in other current assets			(238,217	)		(76,633	)		7,937
		Change in accounts payable			285,630			109,870			9,148
		Change in other current liabilities			(10,289	)		50,749			22,957
		Change in other assets and liabilities			45,182			21,082			(19,284	)

			Net cash provided by operating activities		460,758			475,626			421,218
Investing activities:
	Capital/construction expenditures				(373,566	)		(567,282	)		(504,727	)
	Proceeds from disposition of property, plant and equipment				10,514			92,861			9,102
	Payment received for notes receivable from affiliate				192,620			0			100,000
	Other investments — net				1,521			10,746			2,756

			Net cash used in investing activities		(168,911	)		(463,675	)		(392,869	)
Financing activities:
	Short-term borrowings — net				(200,992	)		(47,121	)		66,195
	Proceeds from issuance of long-term debt — net				101,020			242,846			347,025
	Repayment of long-term debt, including reacquisition premiums				(207,124	)		(99,928	)		(257,737	)
	Proceeds from issuance of common stock				160,000			0			0
	Capital contribution from parent				0			109,372			0
	Proceeds from sale of mandatorily redeemable preferred securities				0			0			187,700
	Redemption of preferred stock				0			0			(181,824	)
	Dividends and redemption premium on preferred stock				0			0			(8,261	)
	Dividends paid to parent				(180,786	)		(185,315	)		(180,430	)

			Net cash (used in) provided by financing activities		(327,882	)		19,854			(27,332	)

	Net increase (decrease) in cash and cash equivalents				(36,035	)		31,805			1,017
	Cash and cash equivalents at beginning of period				51,731			19,926			18,909

	Cash and cash equivalents at end of period			$	15,696		$	51,731		$	19,926

Supplemental disclosure of cash flow information
	Cash paid for interest (net of amount capitalized)			$	162,823		$	203,105		$	188,251
	Cash paid for income taxes (net of refunds received)			$	104,349		$	98,641		$	114,340

The Notes to Consolidated Financial Statements are an integral
part of the Statements of Cash Flow.

PUBLIC SERVICE COMPANY OF COLORADO
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)

			Dec. 31 2000			Dec. 31 1999
ASSETS
Current assets:
	Cash and cash equivalents		$	15,696		$	51,731
	Accounts receivable — net of allowance for bad debts of $11,352 and $2,533, respectively			228,957			189,855
	Accounts receivable from affiliates			0			9,449
	Accrued unbilled revenues			369,018			220,330
	Recoverable purchased gas and electric energy costs			159,013			42,697
	Materials and supplies inventories at average cost			41,106			53,984
	Fuel and gas inventories at average cost			66,211			89,813
	Prepayments and other			15,974			46,292

		Total current assets		895,975			704,151

Property, plant and equipment, at cost:
	Electric utility			4,896,863			4,629,092
	Gas utility			1,345,380			1,289,995
	Other and construction work in progress			876,332			827,273

		Total property, plant and equipment		7,118,575			6,746,360
	Less: accumulated depreciation			(2,576,126	)		(2,373,824	)

		Net property, plant and equipment		4,542,449			4,372,536

Other assets:
	Note receivable from affiliate			0			192,620
	Other investments			11,158			12,679
	Regulatory assets			251,154			290,903
	Deferred charges and other			73,577			70,705

		Total other assets		335,889			566,907

		Total assets	$	5,774,313		$	5,643,594

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	142,043		$	132,823
	Short-term debt			155,200			356,192
	Accounts payable			575,948			309,679
	Accounts payable to affiliates			46,573			27,212
	Taxes accrued			54,718			67,030
	Dividends payable			57,615			44,575
	Recovered electric energy costs			27,060			11,873
	Other			146,309			159,471

		Total current liabilities		1,205,466			1,108,855

Deferred credits and other liabilities:
	Deferred income taxes			543,715			555,829
	Deferred investment tax credits			83,804			89,286
	Regulatory liabilities			45,027			54,652
	Other deferred credits			24,632			25,993
	Customers' advances for construction			70,714			54,826
	Benefit obligations and other			73,028			77,309

		Total deferred credits and other liabilities		840,920			857,895

Long-term debt				1,610,741			1,721,959
Mandatorily redeemable preferred securities of subsidiary trust				194,000			194,000
Common stock and paid-in capital				1,574,835			1,414,835
Retained earnings				348,351			346,050

		Total common stockholder's equity		1,923,186			1,760,885
Commitments and contingencies (see Note 12)

		Total liabilities and equity	$	5,774,313		$	5,643,594

The Notes to Consolidated Financial Statements are an integral
part of the Balance Sheets.

PUBLIC SERVICE COMPANY OF COLORADO
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
(Thousands of Dollars, Except Share Information)

			Common Stock,(1)
			Common Stock,(1)		Paid in Capital		Retained Earnings			Accumulated Other Comprehensive Income
			Shares	Amount	Paid in Capital		Retained Earnings			Accumulated Other Comprehensive Income			Total
Balance at Jan. 1, 1998			100	$	$	1,302,119	$	319,280		$	4,142		$	1,625,541
Comprehensive income:
	Net income							200,103						200,103
	Foreign currency translation adjustment										5,260			5,260
	Sale of subsidiary to affiliate										(9,402	)		(9,402	)

		Comprehensive income												195,961
Dividends declared:
	Common stock, to parent							(188,845	)					(188,845	)
	Preferred stock, $100 par value							(4,166	)					(4,166	)
	Preferred stock, $25 par value							(1,166	)					(1,166	)
Other								7						7

Balance at Dec. 31, 1998			100			1,302,119		325,213						1,627,332
Comprehensive income:
	Net income-Comprehensive income							204,265						204,265
	Dividends declared Common stock, to parent							(183,428	)					(183,428	)
Contribution of capital by parent						109,372								109,372
Contribution of subsidiary's stock by parent (Note 1)						3,344								3,344

Balance at Dec. 31, 1999			100			1,414,835		346,050						1,760,885
Net income-Comprehensive income								196,128						196,128
Dividends declared Common stock, to parent								(193,827	)					(193,827	)
Contribution of capital by parent						160,000								160,000

Balance at Dec. 31, 2000			100	$	$	1,574,835	$	348,351		$			$	1,923,186

(1): Authorized shares of common stock were 100 at Dec. 31, 2000 and 1999 and 1998.

The Notes to Consolidated Financial Statements are an integral
part of the Statements of Stockholder's Equity.

PUBLIC SERVICE COMPANY OF COLORADO
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Thousands of Dollars)

			Dec. 31
			2000			1999
Long-Term Debt
First Mortgage Bonds, Series due:
	Jan. 1, 2001, 6.00%		$	102,667		$	102,667
	April 15, 2003, 6.00%			250,000			250,000
	March 1, 2004, 8.125%			100,000			100,000
	Nov. 1, 2005, 6.375%			134,500			134,500
	June 1, 2006, 7.125%			125,000			125,000
	April 1, 2008, 5.625%			18,000	^(b)		18,000	^(b)
	June 1, 2012, 5.5%			50,000	^(b)		50,000	^(b)
	April 1, 2014, 5.875%			61,500	^(b)		61,500	^(b)
	Jan. 1, 2019, 5.1%			48,750	^(b)		48,750	^(b)
	July 1, 2020, 9.875%			0			70,000
	March 1, 2022, 8.75%			147,840			148,000
	Jan. 1, 2024, 7.25%			110,000			110,000
Unsecured Senior A Notes, due July 15, 2009, 6.875%				200,000			200,000
Secured Medium-Term Notes, due Feb. 1, 2001 — March 5, 2007, 6.45% — 9.25%				226,500			256,500
Other secured long-term debt 13.25%, due in installments through Oct. 1, 2016				29,777			30,298
PSCCC Unsecured Medium-Term Notes due May 30, 2000, 5.86%				0			100,000
PSCCC Unsecured Medium-Term Notes due May 30, 2002, variable rate 7.40% at Dec. 31, 2000				100,000			0
Unamortized discount				(5,952	)		(6,998	)
Capital lease obligations, 11.2% due in installments through May 31, 2025				54,202			56,565

		Total		1,752,784			1,854,782
Less current maturities				142,043			132,823

		Total PSCo long-term debt	$	1,610,741		$	1,721,959

Mandatorily Redeemable Preferred Securities of Subsidiary Trust
	Holding as its sole asset junior subordinated deferrable debentures of PSCo (see Note 6)		$	194,000		$	194,000

Common Stockholder's Equity
	Common stock — authorized 100 shares of $1 par value; 100 shares outstanding in 2000 and 1999		$	0		$	0
	Premium on common stock			1,574,835			1,414,835
	Retained earnings			348,351			346,050

		Total common stockholder's equity	$	1,923,186		$	1,760,885

^(a): Resource recovery financing
^(b): Pollution control financing

The Notes to Consolidated Financial Statements are an integral
part of the Statements of Capitalization.

SOUTHWESTERN PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME
(Thousands of Dollars)
Year ended December 31

			2000			1999		1998
Electric operating revenues			$	1,079,580		$	925,937	$	951,187
Operating expenses:
	Electric fuel and purchased power			573,181			448,099		455,282
	Other operating and maintenance expenses			156,800			138,429		138,679
	Depreciation and amortization			78,526			75,946		78,592
	Taxes (other than income taxes)			47,407			49,290		47,259
	Special charges (see Note 2)			24,345			0		0

		Total operating expenses		880,259			711,764		719,812

Operating income				199,321			214,173		231,375
Other income (deductions) — net				10,400			9,370		7,611
Interest charges and financing costs:
	Interest charges — net of amount capitalized			54,643			53,585		50,453
	Distributions on redeemable preferred securities of subsidiary trust			7,850			7,850		7,850

		Total interest charges and financing costs		62,493			61,435		58,303

Income before income taxes and extraordinary items				147,228			162,108		180,683
Income taxes				58,776			59,399		65,696

Income before extraordinary items				88,452			102,709		114,987
Extraordinary items, net of income taxes of $8,549 (see Note 10)				(18,960	)		0		0

Net income			$	69,492		$	102,709	$	114,987

The Notes to Financial Statements are an integral
part of the Statements of Income.

SOUTHWESTERN PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
Year ended December 31

				2000			1999			1998
Operating activities:
	Net income			$	69,492		$	102,709		$	114,987
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			82,617			78,085			83,103
		Deferred income taxes			45,871			15,922			(8,600	)
		Amortization of investment tax credits			(250	)		(250	)		(250	)
		Allowance for equity funds used during construction			11			(1,040	)		0
		Extraordinary items (see Note 10)			18,960			0			0
		Change in accounts receivable			5,049			(7,738	)		20,358
		Change in inventories			5,766			(1,064	)		(625	)
		Change in other current assets			(146,925	)		(36,212	)		27,300
		Change in accounts payable			33,832			12,285			(43,190	)
		Change in other current liabilities			22,123			(19,195	)		31,699
		Change in other assets and liabilities			(49,378	)		(12,769	)		33,667

			Net cash provided by operating activities		87,168			130,733			258,449
Investing activities:
Capital/construction expenditures					(103,915	)		(118,834	)		(92,218	)
	Allowance for equity funds used during construction				(11	)		1,040			0
	Cost of disposition of property, plant and equipment				(3,433	)		(2,396	)		(2,897	)
	Other investments — net				(6,349	)		(355	)		147

			Net cash used in investing activities		(113,708	)		(120,545	)		(94,968	)
Financing activities:
	Short-term borrowings — net				496,834			83,584			(85,242	)
	Proceeds from issuance of long-term debt — net				0			99,846			0
	Repayment of long-term debt, including reacquisition premiums				(383,145	)		(114,846	)		(179	)
	Capital contribution by parent				0			4,697			0
	Dividends paid to parent				(77,855	)		(83,287	)		(77,696	)

			Net cash provided by (used in) financing activities		35,834			(10,006	)		(163,117	)

	Net increase in cash and cash equivalents				9,294			182			364
	Cash and cash equivalents at beginning of period				1,532			1,350			986

	Cash and cash equivalents at end of period			$	10,826		$	1,532		$	1,350

Supplemental disclosure of cash flow information
	Cash paid for interest (net of amount capitalized)			$	70,857		$	53,819		$	55,739
	Cash paid for income taxes (net of refunds received)			$	17,490		$	51,117		$	69,111

The Notes to Financial Statements are an integral
part of the Statements of Cash Flow.

SOUTHWESTERN PUBLIC SERVICE COMPANY
BALANCE SHEETS
(Thousands of Dollars)

			Dec. 31 2000			Dec. 31 1999
ASSETS
Current assets:
	Cash and cash equivalents		$	10,826		$	1,532
	Accounts receivable — net of allowance for bad debts of $845 and $682, respectively			73,986			74,860
	Accounts receivable from affiliates			4,893			9,068
	Accrued unbilled revenues			87,484			44,631
	Recoverable electric energy costs.			104,249			1,948
	Materials and supplies inventories at average cost			13,500			18,035
	Fuel and gas inventories at average cost			1,061			2,292
	Prepayments and other			38			4,324

		Total current assets		296,037			156,690

Property, plant and equipment, at cost:
	Electric utility			2,884,702			2,802,077
	Other and construction work in progress			115,210			95,477

		Total property, plant and equipment		2,999,912			2,897,554
	Less: accumulated depreciation			(1,199,158	)		(1,123,739	)

		Net property, plant and equipment		1,800,754			1,773,815

Other assets:
	Notes receivable from affiliate			119,036			119,036
	Other investments			12,295			5,946
	Regulatory assets			74,359			104,203
	Prepaid pension asset			61,359			40,087
	Deferred charges and other			28,796			22,384

		Total other assets		295,845			291,656

		Total Assets	$	2,392,636		$	2,222,161

LIABILITIES AND EQUITY
Current liabilities:
	Short-term debt		$	674,579		$	177,746
	Accounts payable			97,285			62,574
	Accounts payable to affiliates			13,107			13,986
	Taxes accrued			19,141			23,486
	Interest accrued			7,139			17,223
	Dividends payable			22,354			20,963
	Current portion of accumulated deferred income taxes			36,307			0
	Other			57,122			32,690

		Total current liabilities		927,034			348,668

Deferred credits and other liabilities:
	Deferred income taxes			362,206			376,245
	Deferred investment tax credits			4,718			4,969
	Regulatory liabilities			1,275			2,785
	Benefit obligations and other			19,268			22,236

		Total deferred credits and other liabilities		387,467			406,235

Long-term debt				226,506			605,875
Mandatorily redeemable preferred securities of subsidiary trust				100,000			100,000
Common stock and paid-in capital				353,099			353,099
Retained earnings				398,530			408,284

		Total common stockholder's equity		751,629			761,383

Commitments and contingencies (see Notes 10 and 12)
		Total Liabilities and Equity	$	2,392,636		$	2,222,161

The Notes to Financial Statements are an integral
part of the Balance Sheets.

SOUTHWESTERN PUBLIC SERVICE COMPANY
STATEMENT OF STOCKHOLDER'S EQUITY
(Thousands of Dollars, Except Share Information)

	Common Stock, $1 par value
	Common Stock, $1 par value		Paid in Capital		Retained Earnings
	Shares	Amount	Paid in Capital		Retained Earnings			Total
Balance at Jan. 1, 1998	100	$	$	348,402	$	349,988		$	698,390
Net income — comprehensive income						114,987			114,987
Dividends declared, common stock to parent						(75,157	)		(75,157	)

Balance at Dec. 31, 1998	100			348,402		389,818			738,220
Net income — comprehensive income						102,709			102,709
Dividends declared, common stock to parent						(84,243	)		(84,243	)
Contribution of capital by parent				4,697					4,697

Balance at Dec. 31, 1999	100			353,099		408,284			761,383
Net income — comprehensive income						69,492			69,492
Dividends declared, common stock to parent						(79,246	)		(79,246	)

Balance at Dec. 31, 2000	100	$	$	353,099	$	398,530		$	751,629

The Notes to Financial Statements are an integral
part of the Statements of Stockholder's Equity.

SOUTHWESTERN PUBLIC SERVICE COMPANY
STATEMENTS OF CAPITALIZATION
(Thousands of Dollars)

			Dec. 31
			2000			1999
Long-Term Debt
First Mortgage Bonds, Series due:
	July 15, 2004, 7.25%		$	0		$	135,000
	March 1, 2006, 6.5%			0			60,000
	July 15, 2022, 8.25%			0			36,000
	Dec. 1, 2022, 8.20%			0			89,000
	Feb. 15, 2025, 8.50%			0			60,267
Unsecured Senior A Notes, due March 1, 2009, 6.2%				100,000			100,000
Pollution control obligations, securing pollution control revenue bonds, Not collateralized by First Mortgage Bonds due:
	July 1, 2011, 5.20%			44,500			44,500
	July 1, 2016, variable rate, 5.10% at Dec. 31, 2000 and 4.7% at Dec. 31, 1999			25,000			25,000
	Sept. 1, 2016, 5.75% series			57,300			57,300
	Less: funds held by Trustee			(168	)		(168	)
Unamortized discount				(126	)		(1,024	)

		Total SPS long-term debt	$	226,506		$	605,875

Mandatorily Redeemable Preferred Securities of Subsidiary Trust
	Holding as its sole asset junior subordinated deferrable debentures of SPS (Note 6)		$	100,000		$	100,000

Common Stockholder's Equity
	Common stock — authorized 200 shares of $1 par value; 100 shares outstanding in 2000 and 1999		$	0		$	0
	Premium on common stock			353,099			353,099
	Retained earnings			398,530			408,284
	Accumulated other comprehensive income (loss)			0			0

		Total common stockholder's equity	$	751,629		$	761,383

The Notes to Financial Statements are an integral
part of the Statements of Capitalization.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Merger and Basis of Presentation

On Aug. 18, 2000, following receipt of all required regulatory approvals, NSP and NCE merged and formed Xcel Energy Inc. Each share of NCE common stock was exchanged for 1.55 shares of Xcel Energy common stock. NSP shares became Xcel Energy shares on a one-for-one basis. Cash was paid in lieu of any fractional shares of Xcel Energy common stock. The merger was structured as tax-free, stock-for-stock exchange for shareholders of both companies (except for fractional shares) and accounted for as a pooling-of-interests. At the time of the merger, Xcel Energy registered as a holding company under the PUHCA.

Pursuant to the merger agreement, NCE was merged with and into NSP. NSP, as the surviving legal corporation, changed its name to Xcel Energy. Also, 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 wholly owned subsidiary of Xcel Energy, which was renamed NSP-Minnesota. The presentation of NSP-Minnesota in this report has been restated for all prior periods for consistency with the post-merger subsidiary.

Consistent with pooling accounting requirements, results and disclosures for all periods prior to the merger have been restated for consistent reporting with post-merger organization and operations. All earnings per share amounts previously reported for NSP and NCE have been restated for presentation on an Xcel Energy share basis.

Business and System of Accounts

This report reflects Xcel Energy's four largest domestic utility subsidiaries, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, which are engaged principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. Xcel Energy and its subsidiaries are subject to the regulatory provisions of the PUHCA. The utility subsidiaries are subject to regulation by the FERC and state utility commissions. All of the utility companies' accounting records conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material aspects.

Principles of Consolidation

NSP-Minnesota and PSCo each have a number of subsidiaries which have been consolidated. In the consolidation process, we eliminate all significant intercompany transactions and balances.

NSP-Wisconsin has several subsidiaries for which it uses the equity method of accounting for its investments and records its portion of earnings from such investments after subtracting income taxes. PSCo had held an interest in an unconsolidated affiliate, which was sold in 1998.

Revenue Recognition

Xcel Energy's utility subsidiaries records utility revenues based on a calendar month, but read meters and bill customers according to a cycle that doesn't necessarily correspond with the calendar month's end. To compensate, we estimate and record unbilled revenues from the monthly meter-reading dates to the month's end.

Xcel Energy's utility subsidiaries have adjustment mechanisms in place that currently provide for the recovery of certain purchased natural gas and electric energy costs. These cost adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically, as

prescribed by the appropriate regulatory agencies, for any difference between the total amount collected under the clauses and the recoverable costs incurred.

PSCo's electric rates in Colorado are adjusted under the ICA, which takes into account changes in energy costs and certain trading gains and losses that are shared with the customer. SPS' rates in Texas and New Mexico have periodic fuel filing and reporting requirements, which can provide cost recovery. NSP-Wisconsin's rates include a cost-of-energy adjustment clause for purchased natural gas, but not for purchased electricity or electric fuel. In Wisconsin, we can request recovery of those electric costs prospectively through the rate review process, which normally occurs every two years, and an interim fuel cost hearing process.

In Colorado, PSCo operates under an electric PBRP, which results in an annual earnings test with the sharing of excess earnings between customers and shareholders. The sharing threshold is earnings in excess of an 11-percent return on equity for 2001 and a 10.50-percent return on equity for 2002. In Texas, SPS operates under an earnings test, in which excess earnings above a certain level are returned to the customer.

NSP-Minnesota and PSCo's rates include monthly adjustments for the recovery of conservation and energy management program costs, which are reviewed annually.

Trading Operations

Effective with year-end 2000 reporting, PSCo changed its policy for the presentation of energy trading operating results. Previously, trading margins were recorded net of costs in electric and natural gas revenues. After the merger, Xcel Energy and PSCo elected to report trading revenues separately from trading costs. Prior years' results have been reclassified for consistency with 2000 reporting.

PSCo's trading revenues and costs of goods sold do not include the revenue and production costs associated with energy produced from generation assets.

Property, Plant, Equipment and Depreciation

Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired, plus net removal cost, is charged to accumulated depreciation and amortization. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses.

Xcel Energy's utility subsidiaries determine the depreciation of their plant by spreading the original cost equally over the plant's useful life. Depreciation expense for Xcel Energy's utility subsidiaries, expressed as a percentage of average depreciable property, for the years ended Dec. 31, is listed in the following table.

	2000	1999	1998
NSP-Minnesota	3.7%	3.9%	3.8%
NSP-Wisconsin	3.3%	3.7%	3.6%
PSCo	2.8%	2.8%	2.8%
SPS	2.7%	2.7%	3.0%

PSCo's property, plant and equipment includes approximately $18 million and $25 million, respectively, for costs associated with the engineering design of the future Pawnee 2 generating station and certain water rights located in southeastern Colorado, also obtained for a future generating station. PSCo is earning a return on these investments based on its weighted average cost of debt in accordance with a CPUC rate order.

Allowance for Funds Used During Construction (AFDC)

AFDC, a noncash item, represents the cost of capital used to finance utility construction activity. AFDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFDC capitalized as a utility construction cost is credited to other income and expense (for equity capital) and interest charges (for debt capital). AFDC amounts capitalized are included in Xcel Energy's rate base for establishing utility service rates. In addition to construction-related amounts, AFDC also is recorded to reflect returns on capital used to finance conservation programs in Minnesota. Interest capitalized as AFDC for Xcel Energy's utility subsidiaries is listed in the following table (in millions of dollars).

	2000		1999		1998
NSP-Minnesota	$	3.8	$	4.7	$	6.8
NSP-Wisconsin	$	2.3	$	1.1	$	0.5
PSCo	$	9.4	$	10.7	$	12.3
SPS	$	4.5	$	2.7	$	4.9

Decommissioning

NSP-Minnesota accounts for the future cost of decommissioning its nuclear generating plants through annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning costs. Our decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends over the estimated lives of the plants. The calculation assumes that NSP-Minnesota and NSP-Wisconsin will recover those costs through rates. For more information on nuclear decommissioning, see Note 13 to the Financial Statements.

PSCo also previously operated a nuclear generating plant, which has been decommissioned. PSCo's cost associated with decommissioning were deferred and are being amortized consistent with regulatory recovery.

Nuclear Fuel Expense

Nuclear fuel expense, which is recorded as NSP-Minnesota's plants use fuel, includes the cost of nuclear fuel used and future spent nuclear fuel disposal, based on fees established by the U.S. Department of Energy (DOE) and NSP-Minnesota's portion of the cost of decommissioning or shutting down the DOE's fuel enrichment facility.

Environmental Costs

We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset based on our expectation that we will recover these costs from customers in future rates. Otherwise, we expense the costs. If an environmental expense is related to facilities we currently use, such as pollution control equipment, we capitalize and depreciate the costs over the life of the plant, assuming the costs are recoverable in future rates or future cash flow.

We record estimated remediation costs, excluding inflationary increases and possible reductions for insurance coverage and rate recovery. The estimates are based on our experience, our assessment of the current situation and the technology currently available for use in the remediation. We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated responsible parties, we estimate and record only our share of the cost. We treat any future costs of restoring sites where operation may extend indefinitely as a capitalized cost of plant retirement.

The depreciation expense levels we can recover in rates include a provision for these estimated removal costs.

Income Taxes

Xcel Energy and its utility subsidiaries file a consolidated federal and combined and separate state income tax returns. Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of taxable income or loss. Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. We use the tax rates that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, we account for the reversal of some temporary differences as current income tax expense. We defer investment tax credits and spread their benefits over the estimated lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which we summarize in Note 14 to the Financial Statements. For more information on income tax, see Note 8 to the Financial Statements.

Derivative Financial Instruments

Xcel Energy's utility subsidiaries utilize a variety of derivatives, including interest rate swaps and locks, foreign currency hedges and energy contracts. The energy contracts are both financial and commodity based, in the energy trading and energy non-trading operations, to reduce exposure to commodity price risk. These contracts consist mainly of commodity futures and options, index or fixed price swaps and basis swaps.

Xcel Energy's utility subsidiaries adopted Emerging Issues Task Force (EITF) 98-10, "Accounting for Energy Trading and Risk Management Activities," effective Jan. 1, 1999. EITF 98-10 requires gains or losses resulting from market value changes on energy trading contracts to be recorded in earnings. The initial adoption of EITF 98-10 had an immaterial impact on Xcel Energy's utility subsidiaries net income.

Energy contracts also are utilized by Xcel Energy's utility subsidiaries in non-trading operations to reduce commodity price risk. Hedge accounting is applied only if the contract reduces the price risk of the underlying hedged item and is designated as a hedge at its inception. Gains and losses related to qualifying hedges of firm commitments or anticipated transactions are deferred and recognized as a component of purchased power or cost of gas sold when settlement occurs. If, subsequent to the inception of the hedge, the underlying transactions are no longer likely to occur, the related gains and losses are recognized currently in income.

A final derivative instrument used by Xcel Energy's utility subsidiaries is the interest rate swap. The cost or benefit of the interest rate swap agreements is recorded as a component of interest expense. None of these derivative financial instruments are reflected on Xcel Energy's utility subsidiaries' balance sheet. For further discussion of risk management and derivative activities, see Note 11 to the Financial Statements.

Use of Estimates

In recording transactions and balances resulting from business operations, Xcel Energy's utility subsidiaries use estimates based on the best information available. We use estimates for such items as plant depreciable lives, tax provisions, uncollectible amounts, environmental costs, unbilled revenues and actuarially determined benefit costs. We revise the recorded estimates when we get better

information or when we can determine actual amounts. Those revisions can affect operating results. Each year we also review the depreciable lives of certain plant assets and revise them if appropriate.

Cash Equivalents

Xcel Energy's utility subsidiaries consider investments in certain debt instruments—with a remaining maturity of three months or less at the time of purchase—to be cash equivalents. Those debt instruments are primarily commercial paper and money market funds.

Inventory

All inventory is recorded at average cost, with the exception of natural gas in underground storage at PSCo, which is recorded using last-in-first-out (LIFO) pricing.

Regulatory Accounting

Xcel Energy's utility subsidiaries account for certain income and expense items using SFAS No. 71—"Accounting for the Effects of Certain Types of Regulation." As discussed in Note 10 to the Financial Statements, SPS' generation business no longer follows SFAS 71. Under SFAS 71:

•: we defer certain costs, which would otherwise be charged to expense, as regulatory assets based on our expected ability to recover them in future rates; and
•: we defer certain credits, which would otherwise be reflected as income, as regulatory liabilities based on our expectation they will be returned to customers in future rates.

We base our estimates of recovering deferred costs and returning deferred credits on specific ratemaking decisions or precedent for each item. We amortize regulatory assets and liabilities consistent with the period of expected regulatory treatment.

Intangible Assets and Deferred Financing Costs

Intangible and other assets included deferred financing costs which we are amortizing over the remaining maturity periods of the related debt. Xcel Energy's utility subsidiaries' deferred financing costs, net of amortization at Dec. 31, 2000 is listed in the following table (in millions of dollars).

NSP-Minnesota	$	13.4
NSP-Wisconsin	$	2.1
PSCo	$	16.6
SPS	$	6.8

Reclassifications

We reclassified certain items in the 1998 and 1999 income statements and the 1999 balance sheets to conform to the 2000 presentation. These reclassifications had no effect on net income or earnings per share. Reported amounts for periods prior to the merger have been restated to reflect the merger as if it had occurred as of Jan. 1, 1998.

2. Merger Costs and Special Charges (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Upon consummation of the merger in 2000, Xcel Energy expensed pretax special charges related to its regulated operations totaling $199 million. During 2000, an allocation of approximately $188 million of merger costs was made to Xcel Energy's utility subsidiaries consistent with prior regulatory filings and is reported on the accompanying financial statements as special charges.

Of the total pretax special charges recorded by Xcel Energy that related to its regulated operations, $159 million was recorded during the third quarter of 2000, and $40 million was recorded during the fourth quarter of 2000. See Note 16 to the Financial Statements for the quarterly impacts on Xcel Energy's utility subsidiaries.

The total pretax charges included $52 million related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE. These transaction costs include investment banker fees, legal and regulatory approval costs, and expenses for support of and assistance with planning and completing the merger transaction.

Also included in the total were $147 million of pretax charges pertaining to incremental costs of transition and integration activities associated with merging operations. These transition costs include approximately $77 million for severance and related expenses associated with staff reductions of 721 employees, 661 of whom were released through February 2001. The staff reductions were non-bargaining positions mainly in corporate and operations support areas. Other transition and integration costs include amounts incurred for facility consolidation, systems integration, regulatory transition, merger communications and operations integration assistance.

The following table summarizes the total special charges expensed by Xcel Energy during 2000, in millions of dollars.

			Expensed Without Accrual				Expense Accrued As Liability						Payments Against Liability
			Expensed Without Accrual				Expense Accrued As Liability						Payments Against Liability					Dec. 31, 2000 * Liability
			3^rd Qtr		4^th Qtr		3^rd Qtr			4^th Qtr			3^rd Qtr		4^th Qtr			Dec. 31, 2000 * Liability
Employee separation and other related costs			$	16	$	3	$	52		$	6		$	0	$	(10	)	$	48
Regulatory transition costs				4		2		5			1			0		(1	)		5
Other transition and integration costs				33		23		0			2			0		0			2

		Total merger transition and integration costs		53		28		57			9			0		(11	)		55
Transaction-related merger costs				49		3		0			0			0		0			0

Total special charges — consolidated				102		31		57			9			0		(11	)		55
Intercompany cost allocations				27		2		(27	)		(2	)

Total special charges — subsidiaries			$	129	$	33	$	30		$	7

Special charge activities for utility subsidiaries:
	NSP-Minnesota			38		13		21			0			0		(2	)		19
	NSP-Wisconsin			7		2		4			0			0		(1	)		3
	PSCo			61		13		2			1			0		(1	)		2
	SPS			19		4		1			0			0		(0	)		1

*: Reported on the balance sheet in other current liabilities.

3. Short-Term Borrowings (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Information on short-term borrowings for 2000 and 1999 is (in thousands, except interest rates):

NSP-Minnesota

In July 2000, NSP-Minnesota closed on a $300 million, 364-day revolving credit facility. This facility provides short-term financing in the form of bank loans and letters of credit, but its primary purpose is support for commercial paper borrowings.

		2000		1999
Commercial paper		$	359,000	$	420,000
Note payable to bank			189		193

	Total short term debt	$	359,189	$	420,193

Weighted average interest rate at year end			6.32%		5.90%

NSP-Wisconsin

NSP-Wisconsin has an intercompany borrowing arrangement with NSP-Minnesota, with interest charged at NSP-Minnesota's short-term borrowing rate. At Dec. 31, 2000 and 1999, NSP-Wisconsin had $15.9 million and $80.8 million, respectively, in short-term borrowings. The weighted average interest rate for NSP-Wisconsin was 6.89 percent at Dec. 31, 2000 and 5.99 percent at Dec. 31, 1999.

PSCo

In July 2000, PSCo and its subsidiary, Public Service of Colorado Credit Corporation (PSCCC), entered into a $600 million, 364-day revolving credit agreement that provides for direct borrowings, but whose primary purpose is to support the issuance of commercial paper by PSCo and PSCCC.

		2000		1999
Commercial paper		$	155,200	$	355,631
Note payable to affiliate			—		561

	Total short term debt	$	155,200	$	356,192

Weighted average interest rate at year end			6.51%		6.09%

SPS

In July 2000, SPS entered into a $500 million credit agreement that matures January 2002. This credit facility was initially used as support for the issuance of commercial paper to fund open market purchases, tender and defeasance of SPS' outstanding first mortgage bonds and other related restructuring costs. SPS is the initial borrower under this credit agreement; however, at the time of separation of the generation assets, the obligations under this credit agreement will be assumed by a newly formed generation company. See Note 10 to the Financial Statements for more information on restructuring.

In February 2001, SPS renewed a $300 million, 364-day revolving credit facility. This facility provides for direct borrowings, but its primary purpose is to support the issuance of commercial paper.

		2000			1999
Commercial paper		$	674,579		$	177,746
Weighted average interest rate at year end			6.55%			5.89%

4. Long-Term Debt (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Except for SPS and other minor exclusions, all property of Xcel Energy's utility subsidiaries is subject to the liens of its first mortgage indentures, which are contracts between the companies and their bond holders. In addition, certain SPS payments under its pollution control obligations are pledged to secure obligations of the Red River Authority of Texas.

The annual sinking-fund requirements of Xcel Energy's utility subsidiaries' first mortgage indentures are the amounts necessary to redeem 1 to 1.5 percent of the highest principal amount of each series of first mortgage bonds at any time outstanding, excluding series issued for pollution control and resource recovery financings and certain other series totaling $2 billion.

NSP-Minnesota, NSP-Wisconsin and PSCo expect to satisfy substantially all of their sinking fund obligations in accordance with the terms of their respective indentures through the application of property additions. SPS has no significant sinking fund requirements.

NSP-Minnesota's 2011 and 2019 series first mortgage bonds have variable interest rates, which currently change at various periods up to 270 days, based on prevailing rates for certain commercial paper securities or similar issues. The 2011 series bonds are redeemable upon seven days notice at the option of the bondholder. NSP-Minnesota also is potentially liable for repayment of the 2019 series when the bonds are tendered, which occurs each time the variable interest rates change. The principal amount of all of these variable rate bonds outstanding represents potential short-term obligations and, therefore, is reported under current liabilities on the balance sheets.

In addition, NSP-Minnesota's first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy, the holder of its common stock. Even with these restrictions, NSP-Minnesota could have paid more than $800 million in additional cash dividends on common stock at Dec. 31, 2000.

Maturities and sinking fund requirements for long-term debt for Xcel Energy's utility subsidiaries are listed in the following table (in millions of dollars):

	NSP-Minnesota		NSP-Wisconsin		PSCo		SPS
2001	$	304	$	1	$	142	$	—
2002	$	12	$	1	$	119	$	—
2003	$	223	$	41	$	284	$	—
2004	$	8	$	1	$	149	$	—
2005	$	82	$	1	$	139	$	—

5. Preferred Stock (PSCo and SPS)

PSCo has 10 million shares of cumulative preferred stock, $0.01 par value, authorized. At Dec. 31, 2000 and 1999, PSCo had no shares of preferred stock outstanding.

SPS has 10 million shares of cumulative preferred stock, $1 par value, authorized. At Dec. 31, 2000 and 1999, SPS had no shares of preferred stock outstanding.

6. Mandatorily Redeemable Preferred Securities of Subsidiary Trusts (NSP-Minnesota, PSCo and SPS)

In 1997, NSP Financing I, a wholly owned, special-purpose subsidiary trust of NSP-Minnesota, issued $200 million of 7.875 percent trust preferred securities that mature in 2037. Distributions paid by the subsidiary trust on the preferred securities are financed through interest payments on debentures issued by NSP-Minnesota and held by the subsidiary trust, which are eliminated in consolidation. The preferred securities are redeemable at $25 per share beginning in 2002. Distributions and redemption payments are guaranteed by NSP-Minnesota.

In 1998, PSCo Capital Trust I, a wholly owned, special-purpose subsidiary trust of PSCo, issued $194 million of 7.60 percent trust preferred securities that mature in 2038. Distributions paid by the subsidiary trust on the preferred securities are financed through interest payments on debentures issued by PSCo and held by the subsidiary trust, which are eliminated in consolidation. The securities are redeemable at the option of PSCo after May 2003, at 100 percent of the principal amount outstanding plus accrued interest. Distributions and redemption payments are guaranteed by PSCo.

In 1996, SPS Capital I, a wholly owned, special-purpose subsidiary trust of SPS, issued $100 million of 7.85 percent trust preferred securities that mature in 2036. Distributions paid by the subsidiary trust on the preferred securities are financed through interest payments on debentures issued by SPS and held by the subsidiary trust, which are eliminated in consolidation. The securities are redeemable at the option of SPS after October 2001, at 100 percent of the principal amount plus accrued interest. Distributions and redemption payments are guaranteed by SPS.

Distributions paid to preferred security holders are reflected as a financing cost in the accompanying Income Statements along with interest expense.

7. Joint Plant Ownership (NSP-Minnesota and PSCo)

The investments by Xcel Energy's utility subsidiaries in jointly owned plants as of Dec. 31, 2000 are (in thousands):

	Plant in Service		Accumulated Depreciation		Construction Work in Progress			Ownership %
NSP-Minnesota-Sherco Unit 3	$	607,568	$	252,096	$	1,095		59.0
PSCo:
Hayden Unit 1		82,800		35,767		1,172		75.5
Hayden Unit 2		78,347		39,058		161		37.4
Hayden Common Facilities		27,145		2,071		258		53.1
Craig Units 1 & 2		57,710		29,248		—		9.7
Craig Common Facilities Units 1, 2 & 3		21,012		8,339		(21	)	6.5–9.7
Transmission Facilities, including Substations		81,769		27,349		609		42.0–73.0

Total PSCo	$	348,783	$	141,832	$	2,179

NSP-Minnesota is part owner of Sherco 3, an 860 megawatt coal-fired electric generating unit. NSP-Minnesota is the operating agent under the joint ownership agreement. The PSCo assets include approximately 320 Mw of generating capacity. Both NSP-Minnesota and PSCo are responsible for their proportionate share of operating expenses and construction expenditures for the jointly owned plants.

8. Income Taxes (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

NSP-Minnesota

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The reasons for the difference are:

			2000			1999			1998
Federal statutory rate				35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
	State income taxes, net of federal income tax benefit			7.2	%		5.9	%		5.4	%
	Life insurance policies			(0.3	)%		(0.2	)%		(0.1	)%
	Tax credits recognized			(4.5	)%		(3.5	)%		(2.7	)%
	Regulatory differences — utility plant items			3.8	%		2.2	%		0.7	%
	Non-deductibility of merger costs			4.5	%		0.0	%		0.0	%
	Other—net			(0.4	)%		(1.4	)%		(1.0	)%

Effective income tax rate				45.3	%		38.0	%		37.3	%

Income taxes comprise the following expense (benefit) items (in thousands of dollars):
	Current federal tax expense		$	80,085		$	87,480		$	118,427
	Current state tax expense			19,980			23,036			28,420
	Current federal tax credits			(799	)		(765	)		(705	)
	Deferred federal tax (credits)			(1,206	)		(4,052	)		(12,328	)
	Deferred state tax expense (credits)			2,546			56			(783	)
	Deferred investment tax credits			(8,415	)		(8,324	)		(8,318	)

		Total income tax expense	$	92,191		$	97,431		$	124,713

The components of net deferred tax liability (current and noncurrent portions) at December 31 were:

			2000		1999
			(Thousands of dollars)
Deferred tax liabilities:
	Differences between book and tax bases of property		$	713,041	$	723,953
	Regulatory assets			82,857		75,672
	Tax benefit transfer leases			18,775		23,349
	Other			17,366		19,802

		Total deferred tax liabilities	$	832,039	$	842,776

Deferred tax assets:
	Regulatory liabilities		$	61,937	$	61,965
	Employee benefits			51,484		50,537
	Deferred investment tax credits			36,220		39,592
	Other			5,981		5,676

		Total deferred tax assets	$	155,622	$	157,770

	Net deferred tax liability		$	676,417	$	685,006

NSP-Wisconsin

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The reasons for the difference are:

			2000			1999			1998
Federal statutory rate				35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
	State income taxes, net of federal income tax benefit			5.2	%		5.3	%		4.9	%
	Tax credits recognized			(1.6	)%		(1.3	)%		(1.6	)%
	Equity income from unconsolidated affiliates			(0.4	)%		(0.3	)%		(0.6	)%
	Regulatory differences — utility plant items			(1.0	)%		1.6	%		0.6	%
	Non-deductibility of merger costs			3.2	%		0.0	%		0.0	%
	Other — net			0.2	%		0.7	%		0.6	%

Effective income tax rate				40.6	%		41.0	%		38.9	%

Income taxes comprise the following expense (benefit) items (in thousands of dollars):
	Current federal tax expense		$	14,924		$	17,986		$	13,016
	Current state tax expense			3,500			4,459			2,906
	Deferred federal tax expense			2,487			3,103			4,381
	Deferred state tax expense			606			592			1,024
	Deferred investment tax credits			(827	)		(838	)		(859	)

		Total income tax expense	$	20,690		$	25,302		$	20,468

The components of net deferred tax liability (current and noncurrent portions) at December 31 were:

			2000		1999
			(Thousands of dollars)
Deferred tax liabilities:
	Differences between book and tax bases of property		$	115,002	$	112,461
	Regulatory assets			14,088		14,266
	Other			11,717		9,988

		Total deferred tax liabilities	$	140,807	$	136,715

Deferred tax assets:
	Regulatory liabilities		$	6,676	$	7,286
	Deferred investment tax credits			6,611		6,927
	Employee benefits			8,434		3,941
	Other			766		4,383

		Total deferred tax assets	$	22,487	$	22,537

	Net deferred tax liability		$	118,320	$	114,178

PSCo

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The reasons for the difference are:

			2000			1999			1998
Federal statutory rate				35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
	State income taxes, net of federal income tax benefit			1.9	%		1.4	%		2.0	%
	Life insurance policies			(6.8	)%		(5.4	)%		(4.8	)%
	Tax credits recognized			(3.1	)%		(1.7	)%		(1.6	)%
	Equity income from unconsolidated affiliates			0.0	%		0.0	%		(0.9	)%
	Regulatory differences — utility plant items			2.7	%		2.4	%		2.2	%
	Non-deductibility of merger costs			3.3	%		0.0	%		0.0	%
	Other — net			1.4	%		0.4	%		1.8	%

Effective income tax rate				34.4	%		32.1	%		33.7	%

Income taxes comprise the following expense (benefit) items (in thousands of dollars):
	Current federal tax expense		$	91,281		$	81,230		$	91,122
	Current state tax expense			7,037			4,700			8,176
	Current federal tax credits			(3,699	)		0			0
	Deferred federal tax expense			11,835			13,998			6,014
	Deferred state tax expense			1,797			1,819			1,078
	Deferred investment tax credits			(5,481	)		(5,173	)		(4,896	)

		Total income tax expense	$	102,770		$	96,574		$	101,494

The components of net deferred tax liability (current and noncurrent portions) at December 31 were:

			2000		1999
			(Thousands of dollars)
Deferred tax liabilities:
	Differences between book and tax bases of property		$	506,408	$	543,370
	Employee benefits			45,553		39,277
	Regulatory assets			40,779		42,811
	Other			23,416		15,764

		Total deferred tax liabilities	$	616,156	$	641,222

Deferred tax assets:
	Deferred investment tax credits		$	31,750	$	33,887
	Regulatory liabilities			19,471		20,848
	Other			17,128		34,190

		Total deferred tax assets	$	68,349	$	88,925

	Net deferred tax liability		$	547,807	$	552,297

SPS

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The reasons for the difference are:

			2000			1999			1998
Federal statutory rate				35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
	State income taxes, net of federal income tax benefit			0.9	%		0.0	%		0.8	%
	Life insurance policies			(0.1	)%		(0.1	)%		0.0	%
	Tax credits recognized			(0.2	)%		(0.2	)%		(0.1	)%
	Regulatory differences — utility plant items			2.9	%		0.7	%		(0.1	)%
	Non-deductibility of merger costs			2.1	%		0.0	%		0.3	%
	Extraordinary item			5.8	%		0.0	%		0.0	%
	Other — net			(0.7	)%		1.2	%		0.5	%

Effective income tax rate including extraordinary items				45.7	%		36.6	%		36.4	%
	Extraordinary items			(5.8	)%		0.0	%		0.0	%

Effective income tax rate excluding extraordinary items				39.9	%		36.6	%		36.4	%

Income taxes comprise the following expense (benefit) items (in thousands of dollars):
	Current federal tax expense		$	13,063		$	44,072		$	71,954
	Current state tax expense			815			(345	)		2,592
	Deferred federal tax expense			43,729			15,380			(8,266	)
	Deferred state tax expense			1,419			542			(334	)
	Deferred investment tax credits			(250	)		(250	)		(250	)

		Income tax expense excluding extraordinary items		58,776			59,399			65,696
	Tax expense (benefit) on extraordinary items			(8,549	)		0			0

		Total income tax expense	$	50,227		$	59,399		$	65,696

The components of net deferred tax liability (current and noncurrent portions) at December 31 were:

			2000		1999
			(Thousands of dollars)
Deferred tax liabilities:
	Differences between book and tax bases of property		$	310,554	$	329,930
	Regulatory assets			29,985		29,734
	Other			73,839		35,080

		Total deferred tax liabilities	$	414,378	$	394,744

Deferred tax assets:
	Deferred investment tax credits		$	820	$	1,795
	Regulatory liabilities			456		990
	Other			14,590		15,784

		Total deferred tax assets	$	15,866	$	18,569

	Net deferred tax liability		$	398,512	$	376,175

9. Benefit Plans and Other Postretirement Benefits (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Xcel Energy offers various benefit plans to its benefit employees. Approximately 45 percent of benefit employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2000, NSP-Minnesota had 2,122 and NSP-Wisconsin had 476 union employees covered under a collective-bargaining agreement, which expires at the end of 2004. PSCo had 1,969 union employees covered under a collective-bargaining agreement, which expires in May 2003. SPS had 776 union employees covered under a collective-bargaining agreement, which expires in October 2002.

Pension Benefits

Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all utility employees. Benefits are based on a combination of years of service, the employee's average pay and Social Security benefits.

Xcel Energy's policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws. Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities.

A comparison of the actuarially computed pension benefit obligation and plan assets at Dec. 31, 2000 and 1999 for all Xcel Energy plans on a combined basis is presented in the following table (in thousands).

	2000			1999
Change in Benefit Obligation
Obligation at January 1	$	2,170,627		$	2,157,255
Service cost		59,066			63,674
Interest cost		172,063			154,619
Acquisitions		52,800			—
Plan amendments		2,649			184,255
Actuarial (gain) loss		1,327			(225,355	)
Benefit payments		(204,394	)		(163,821	)

Obligation at December 31	$	2,254,138		$	2,170,627

Change in Fair Value of Plan Assets
Fair value of plan assets at January 1	$	3,763,293		$	3,460,740
Actual return on plan assets		91,846			466,374
Acquisitions		38,412			—
Benefit payments		(204,394	)		(163,821	)

Fair value of plan assets at December 31	$	3,689,157		$	3,763,293

Funded Status at December 31
Net asset	$	1,435,019		$	1,592,666
Unrecognized transition (asset) obligation		(16,631	)		(23,945	)
Unrecognized prior-service cost		228,436			247,632
Unrecognized (gain) loss		(1,421,690	)		(1,680,616	)

Xcel Energy prepaid pension asset recorded	$	225,134		$	135,737

NSP-MN prepaid pension asset recorded	$	107,784		$	52,801

NSP-WI prepaid pension asset recorded	$	18,561		$	12,915

PSCo prepaid pension asset recorded	$	43,362		$	26,786

SPS prepaid pension asset recorded	$	61,359		$	40,087

Significant assumptions	2000		1999
Discount rate (year-end)	7.75	%	7.5-8.0	%
Expected long-term increase in compensation level	4.50	%	4.0-4.5	%
Expected average long-term rate of return on assets	8.5-10.0	%	8.5-10.0	%

The components of net periodic pension cost (credit) for all Xcel Energy plans are (in thousands):

	2000			1999			1998
Xcel Energy
Service cost	$	59,066		$	63,674		$	55,545
Interest cost		172,063			154,619			145,574
Expected return on plan assets		(292,580	)		(259,074	)		(233,191	)
Amortization of transition asset		(7,314	)		(7,314	)		(7,314	)
Amortization of prior-service cost		19,197			17,855			6,209
Amortization of net gain		(60,676	)		(40,217	)		(30,607	)

Net periodic pension cost (credit) under SFAS 87	$	(110,244	)	$	(70,457	)	$	(63,784	)

NSP-MN
Net periodic pension cost (credit) under SFAS 87	$	(56,182	)	$	(36,469	)	$	(35,545	)
Credits not recognized due to effects of regulation		56,182			36,469			35,545

Net benefit cost (credit) recognized for financial reporting	$	—		$	—		$	—

NSP-WI
Net SFAS 87 benefit cost (credit) recognized for reporting	$	(6,369	)	$	(3,360	)	$	(3,354	)

PSCo
Net SFAS 87 benefit cost (credit) recognized for reporting	$	(16,825	)	$	(11,697	)	$	(5,093	)

SPS
Net SFAS 87 benefit cost (credit) recognized for reporting	$	(21,352	)	$	(15,476	)	$	(15,175	)

Additionally, Xcel Energy maintains noncontributory defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of Xcel Energy's operating cash flows.

Defined Contribution Plans

NSP-Minnesota and NSP-Wisconsin participate in 401(K) and other defined contribution plans. Total contributions to these plans were approximately $12 million in 2000, $11 million in 1999 and $9 million in 1998. PSCo and SPS participate in 401(K) and other defined contribution plans. Total contributions to these plans were approximately $11 million in 2000, $10 million in 1999 and $12 million in 1998.

Xcel Energy has a leveraged Employee Stock Ownership Program (ESOP) that covers substantially all employees of NSP-Minnesota and NSP-Wisconsin. NSP-Minnesota makes contributions to this noncontributory, defined contribution plan to the extent it realizes a tax savings from dividends paid on certain ESOP shares. ESOP contributions have no material effect on NSP-Minnesota or NSP-Wisconsin's earnings because the contributions are essentially offset by the tax savings provided by the dividends paid on ESOP shares. Leveraged ESOP shares are allocated to participants as ESOP loans are repaid with dividends on Xcel Energy stock held by the ESOP.

Postretirement Health Care Benefits

Xcel Energy has contributory health and welfare benefit plans that provide health care and death benefits to most Xcel Energy retirees. The plan was terminated for nonbargaining employees retiring after 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin after 1999.

In conjunction with the 1993 adoption of SFAS No. 106—"Employers' Accounting for Postretirement Benefits Other Than Pension," Xcel Energy elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.

Regulatory agencies for nearly all of Xcel Energy's retail and wholesale utility customers have allowed rate recovery of accrued benefit costs under SFAS 106. PSCo transitioned to full accrual accounting for SFAS 106 costs between 1993 and 1997, consistent with the accounting requirements for rate regulated enterprises. The Colorado jurisdictional SFAS 106 costs deferred during the transition period are being amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012. NSP-Minnesota also transitioned to full accrual accounting for SFAS 106 costs, with regulatory differences fully amortized prior to 1997.

Additionally, certain state agencies, which regulate Xcel Energy's utility subsidiaries, have issued guidelines related to the funding of SFAS 106 costs. SPS is required to fund SFAS 106 costs for Texas and New Mexico jurisdictional amounts collected in rates, and PSCo is required to fund SFAS 106 costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. Minnesota and Wisconsin retail regulators require external funding of accrued SFAS 106 costs to the extent such funding is tax advantaged. Plan assets held in external funding trusts principally consist of investments in equity mutual funds, fixed-income securities and cash equivalents.

A comparison of the actuarially computed benefit obligation and plan assets at Dec. 31, 2000 and 1999 for all Xcel Energy postretirement health care plans is presented in the following table (in thousands).

	2000			1999
Change in Benefit Obligation:
Obligation at January 1	$	533,458		$	616,957
Service cost		5,679			4,680
Interest cost		43,477			35,583
Acquisitions		16,445			—
Plan amendments		—			(80,840	)
Plan participants' contributions		4,358			3,818
Actuarial (gain) loss		10,501			(5,581	)
Benefit payments		(37,191	)		(41,159	)

Obligation at December 31	$	576,727		$	533,458

Change in Fair Value of Plan Assets
Fair value of plan assets at January 1	$	201,767		$	180,742
Actual return on plan assets		10,069			11,981
Plan participants' contributions		4,358			3,818
Employer contributions		44,263			34,652
Benefit payments		(37,191	)		(29,426	)

Fair value of plan assets at December 31	$	223,266		$	201,767

Funded Status at December 31
Net obligation	$	353,461		$	331,691
Unrecognized transition asset (obligation)		(202,871	)		(219,644	)
Unrecognized prior-service credit		13,789			14,999
Unrecognized gain (loss)		(11,126	)		5,559

Xcel Energy accrued benefit liability recorded	$	153,253		$	132,605

NSP-MN accrued benefit liability recorded	$	64,115		$	67,374

NSP-WI accrued benefit liability recorded	$	4,588		$	4,167

PSCo accrued benefit liability recorded	$	53,940		$	51,080

SPS accrued benefit liability recorded	$	6,657		$	6,086

Significant assumptions:		2000		1999
Discount rate (year-end)		7.75	%	7.5-8.0	%
Expected average long-term rate of return on assets		8.0-9.5	%	8.0-9.5	%

The assumed health care cost trend rate for 2000 is approximately 7.5 percent, decreasing gradually to 5.5 percent in 2004 and remaining level thereafter. A 1 percent increase in the assumed health care cost trend rate would have the following effects (in thousands):

	Xcel Energy			NSP-MN			NSP-WI			PSCo			SPS
Effect of changes in the assumed health care cost trend rate:
1% increase in APBO components at Dec. 31, 2000	$	49,331		$	11,057		$	1,901		$	27,466		$	4,398
1% decrease in APBO components at Dec. 31, 2000	$	(42,857	)	$	(9,641	)	$	(1,658	)	$	(23,948	)	$	(3,835	)
1% increase in service and interest components of the net periodic cost	$	3,821		$	747		$	125		$	2,131		$	344
1% decrease in service and interest components of the net periodic cost	$	(3,308	)	$	(652	)	$	(109	)	$	(1,860	)	$	(300	)

The components of net periodic postretirement benefit cost of all Xcel Energy's plans are (in thousands):

	2000			1999			1998
Service cost	$	5,679		$	4,680		$	8,164
Interest cost		43,477			35,583			42,399
Expected return on plan assets		(17,902	)		(15,003	)		(12,349	)
Amortization of transition obligation		16,773			17,461			23,411
Amortization of prior-service cost (credit)		(1,211	)		(1,803	)		(932	)
Amortization of net loss (gain)		915			(5	)		(790	)

Net periodic postretirement benefit costs under SFAS 106		47,731			40,913			59,903
Additional cost recognized due to effects of regulation		6,641			4,029			5,673

Net cost recognized for financial reporting	$	54,372		$	44,942		$	65,576

NSP-MN
Net periodic postretirement benefit costs recognized — SFAS 106	$	10,718		$	8,265		$	22,220

NSP-WI
Net periodic postretirement benefit costs recognized — SFAS 106	$	852		$	1,053		$	3,335

PSCo
Net periodic postretirement benefit costs under SFAS 106	$	28,323		$	26,278		$	26,044
Additional cost recognized due to effects of regulation		3,890			3,891			5,534

Net cost recognized for financial reporting	$	32,213		$	30,169		$	31,578

SPS
Net periodic postretirement benefit costs under SFAS 106	$	3,696		$	3,745		$	3,295
Additional cost recognized due to effects of regulation		2,751			138			139

Net cost recognized for financial reporting	$	6,447		$	3,883		$	3,434

10. Electric Utility Restructuring (SPS)

Restructuring legislation has been enacted in Texas and New Mexico, as summarized below. SPS has made and continues to make filings with the PUCT and the New Mexico Public Regulation Commission (NMPRC) to address critical issues related to SPS transition plans to implement retail competition.

New Mexico Restructuring—In April 1999, New Mexico enacted the Electric Utility Restructuring Act of 1999, which provides for customer choice. The legislation provides for recovery of no less than 50 percent of stranded costs for all utilities. Transition costs must be approved by the NMPRC prior to being recovered through a non-bypassable wires charge, which must be included in transition plan filings. SPS must separate its utility operations into at least two entities: energy generation and competitive services, and transmission and distribution utility services, either by the creation of separate affiliates that may be owned by a common holding company or by the sale of assets to one or more third parties. A regulated company, in general, is prohibited from providing unregulated services. In May 2000, the NMPRC approved:

•: customer choice for residential, small commercial and educational customers by January 2002;
•: customer choice for commercial and industrial customers by July 2002; and
•: completion of SPS corporate separation by August 2001.

Texas Restructuring—In June 1999, an electric utility restructuring act (SB-7) was passed in Texas, which provides for the implementation of retail competition for most areas of the state, including SPS' service area, beginning January 2002. The PUCT can delay the date for full retail competition if a power region is unable to offer fair competition and reliable service during the 2001 pilot projects. The legislation requires:

•: a rate freeze for all customers until January 2002;
•: an annual earnings test through 2001;
•: a 6 percent rate reduction for those residential and small commercial customers who choose not to switch suppliers at the start of retail competition;
•: the unbundling of business activities, costs and rates relating to generation, transmission and distribution, and retail services;
•: reductions in NO_x and SO² emissions; and
•: the recovery of stranded costs.

SB-7 requires each utility to unbundle its business activities into three separate legal entities: a power generation company, a regulated transmission and distribution company, and a retail electric provider. SB-7 limits the market share that a single generation provider can control to 20 percent of the generating capacity within a qualified power region. The establishment of a qualified power region with multiple generation suppliers is required under SB-7 in order to implement full retail competition. SPS must return any excess earnings indicated in the annual earnings tests above it last allowed rate of return for 1999, 2000 and 2001 or alternatively may direct any excess earnings to improvements in

transmission and distribution facilities, to capital expenditures to improve air quality or to accelerate the amortization of regulatory assets, subject to PUCT approval.

The Texas legislature is currently considering amendments to SB-7 that would delay the implementation of business separation and customers choice in SPS's market area for 5 years.

Implementation—SPS filed its business separation plan in Texas during the first quarter of 2000 for the unbundling of power generation, transmission, and distribution and retail electric provider services. In April 2000, the PUCT approved SPS' business separation plan. The plan provides for the separation of all competitive energy services, the establishment of an Xcel Energy customer care company, which will provide customer services for all of Xcel Energy's operating utilities, and a formal code of conduct and compliance manual for managing affiliate transactions.

Subject to all required approvals and indebtedness restrictions, it is anticipated that all generation-related and certain other assets and liabilities will be transferred at net book value to newly formed affiliates in accordance with SPS' business separation plan. It is expected that SPS and its affiliates will be capitalized consistent with their respective business operations.

In April 2000, SPS filed with the PUCT a stipulation agreement that specifically addresses SPS' implementation plans to meet the requirements of the Texas restructuring legislation. The stipulation provides for the implementation of full retail customer choice by SPS in its Texas service region, including the future divestiture of certain SPS generation assets. Subject to certain market conditions and confirmation by the SEC that the sale would not violate pooling accounting treatment, SPS agreed to divest at least 1,750 megawatts by January 2002, and specifically identified the plants that it would sell in connection with additional divestitures required to establish a qualified power region under SB-7. In subsequent discussions, the SEC has indicated the sale of generation assets prior to August 2002 would violate pooling accounting. For SPS to comply with this qualified power region requirement and to implement full customer choice in Texas, between 2,843 megawatts and 3,184 megawatts of existing power generation assets or capacity must be sold to third party non-affiliates. SPS has committed to complete these divestitures by January 2006. In May 2000, the PUCT issued an order approving the stipulation. SPS has committed to transfer functional control of its electric transmission system to a regional transmission organization that will operate the transmission systems of multiple owners in the central United States.

SPS filed a rate case in March 2000 to set the rates for distribution services in Texas, which are to be unbundled and implemented in January 2002. SPS requested recovery of all jurisdictional costs associated with restructuring in Texas. Hearings and a final rate order are not expected before August 2001.

In June 2000, SPS filed its transition plan with the NMPRC. SPS filed to establish rates for the transmission and distribution business in New Mexico, requesting approval of its corporate restructuring/separation and other associated matters. Hearings were held in October and November 2000. Final approval is not expected until mid-2001.

Financial Impact—With the issuance of a final written order by the PUCT in May 2000, addressing the implementation of electric utility restructuring, SPS discontinued regulatory accounting under SFAS 71 for the generation portion of its business during the second quarter of 2000. Consistent with current accounting rules, this resulted in extraordinary charges in the second and third quarters of 2000. During the second quarter of 2000, SPS wrote off its generation-related regulatory assets and liabilities, totaling approximately $19.3 million before taxes. This resulted in an after-tax extraordinary charge of approximately $13.7 million against the earnings of Xcel Energy and SPS. During the third quarter of 2000, SPS recorded an extraordinary charge of $8.2 million before tax, or $5.3 million after tax, related to the tender offer and defeasance of approximately $295 million of first mortgage bonds. The first mortgage bonds were defeased to facilitate the eventual divestiture of generation assets.

SPS transmission and distribution business continues to meet the requirements of SFAS 71, as that business is expected to remain regulated.

Additionally, there may be other significant financial implications of implementing SB-7 and electric restructuring in New Mexico. These implications include, but are not limited to investments in information technology, establishing an independent operation of the electric transmission systems, implementing the procedures to govern affiliate transactions, the pricing of unbundled energy services and the regulatory recovery of incurred costs related to these issues. These costs could be as much as $75 million. The total impacts of restructuring are unknown at this time and may have a significant financial impact on the financial position, results of operations and cash flows of Xcel Energy and SPS.

11. Financial Instruments (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Fair Values

For cash, cash equivalents and short-term investments, the carrying amount approximates fair value because of the short maturity of those instruments. The fair values of Xcel Energy's utility subsidiaries' long-term investments, mainly debt securities in an external nuclear decommissioning fund, are estimated based on quoted market prices for those or similar investments. The fair value of Xcel Energy's utility subsidiaries' long-term debt and the mandatorily redeemable preferred securities are estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.

The fair value estimates presented are based on information available to management as of Dec. 31, 2000 and 1999. These fair value estimates have not been comprehensively revalued for purposes of these financial statements since that date, and current estimates of fair values may differ significantly from the amounts presented herein. The estimated fair values of recorded financial instruments for the utility subsidiaries of Xcel Energy at December 31 are as follows.

NSP-Minnesota

	2000				1999
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Thousands of dollars)
Mandatorily redeemable preferred securities	$	200,000	$	198,000	$	200,000	$	174,000
Long-term investments	$	563,812	$	563,812	$	517,129	$	517,129
Long-term debt, including current portion	$	1,352,768	$	1,322,163	$	1,442,304	$	1,379,606

NSP-Wisconsin

	2000				1999
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Thousands of dollars)
Long-term debt, including current portion	$	313,034	$	308,415	$	231,950	$	216,458

PSCo

	2000				1999
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Thousands of dollars)
Mandatorily redeemable preferred securities	$	194,000	$	185,270	$	194,000	$	168,000
Long-term investments	$	6,017	$	5,904	$	20,286	$	17,976
Long-term debt, including current portion	$	1,752,784	$	1,763,074	$	1,854,782	$	1,778,534

SPS

	2000				1999
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Thousands of dollars)
Mandatorily redeemable preferred securities	$	100,000	$	98,000	$	100,000	$	85,240
Long-term investments	$	5,323	$	4,808	$	5,885	$	3,820
Long-term debt, including current portion	$	226,506	$	226,958	$	605,875	$	592,350

Guarantees

NSP-Minnesota

NSP-Minnesota has sold a portion of its other receivables to a third party. The portion of the receivables sold consisted of customer loans to local and state government entities for energy efficiency improvements under various conservation programs offered by NSP-Minnesota. Under the sales agreements, NSP-Minnesota is required to guarantee repayment to the third party of the remaining loan balances. At Dec. 31, 2000, the outstanding balance of the loans was approximately $18.1 million. Based on prior collection experience of these loans, NSP-Minnesota believes that losses under the loan guarantees, if any, would have an immaterial impact on the results of operations.

SPS

In connection with an agreement for the sale of electric power, SPS guaranteed certain obligations of a customer totaling approximately $27.8 million at Dec. 31, 2000. These obligations related to the construction of certain utility property that, in the event of default by the customer, would revert to SPS.

In June 2000, Xcel Energy entered into a guarantee on behalf of BNP Paribas in connection with a letter of credit provided by BNP Paribas at the request of SPS in the amount of $5 million, expiring March 2002. The letter of credit is required to indemnify former SPS board of directors.

Derivatives

NSP-Minnesota and PSCo's regulated energy marketing operations use a combination of energy futures and forward contracts, along with physical supply to hedge market risks in the energy market. Management believes the risk of counterparty nonperformance with regards to any of the hedging transactions is not significant. The notional value of these contracts and realized net gain if the contracts were terminated at Dec. 31, 2000 are as follows (in millions of dollars):

		NSP-Minnesota			PSCo
Notional value		$	26.7		$	63.7
Realized net gain if terminated			10.5			8.2

SPS has an interest rate swap with a notional amount of $25 million, converting variable rate debt to a fixed rate. The approximate termination cost of SPS's swaps was $4 million at Dec. 31, 2000.

Letters of Credit

Xcel Energy's utility subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. The following table details the letter of credits outstanding for Xcel Energy's utility subsidiaries at Dec. 31, 2000 (in millions of dollar). The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

NSP-Minnesota		PSCo		SPS
$29.4		$13.2		$11.2

12. Commitments and Contingent Liabilities (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Legislative Resource Commitments (NSP-Minnesota)

In 1994, NSP-Minnesota received Minnesota legislative approval for additional on-site temporary spent fuel storage facilities at its Prairie Island nuclear power plant, provided NSP-Minnesota satisfies certain requirements. Seventeen dry cask containers were approved. As of Dec. 31, 2000, NSP-Minnesota had loaded twelve casks. The Minnesota Legislature established several energy resource and other commitments for NSP-Minnesota to obtain the Prairie Island temporary nuclear fuel storage facility approval. These commitments can be met by building, purchasing, or in the case of biomass, converting generation resources.

The 1994 legislation requires NSP-Minnesota to have 425 megawatts of wind resources contracted by Dec. 31, 2002. Of this commitment, approximately 80 megawatts remain to be contracted. During 1999, the MPUC ordered an additional 400 Mw to be contracted by 2012, subject to least-cost determinations. The 1994 legislation also requires NSP-Minnesota to contract for 125 megawatts of biomass-fueled energy, which has essentially been fulfilled.

Other commitments established by the Legislature include a discount for low-income electric customers, required conservation improvement expenditures and various study and reporting requirements to a legislative electric energy task force. NSP-Minnesota has implemented programs to meet the legislative commitments. NSP-Minnesota's capital commitments include the known effects of the Prairie Island legislation. The impact of the legislation on future power purchase commitments and other operating expenses is not yet determinable.

Tax Matters (PSCo)

PSR Investments, Inc. (PSRI), a subsidiary of PSCo, owns and manages permanent life insurance policies on certain past and present employees. The IRS has issued a Notice of Proposed Adjustment proposing to disallow interest expense related to corporate owned life insurance (COLI) policy loans taken in tax years 1993-1997. The total disallowance of interest expense deductions for the five years as proposed by the IRS is approximately $175 million. A request for technical advice from the IRS National Office with respect to the proposed adjustment is pending. Interest expense deductions for the period 1998 through 2000 totals approximately $168 million.

Management is vigorously contesting this issue. While the outcome of this matter cannot be predicted, management believes that PSRI's tax deduction of interest expense on life insurance policy loans was in full compliance with the tax law and believes that the resolution of this matter will not have a material adverse impact on Xcel Energy's financial position, results of operations or cash flows. For this reason, PSRI has not recorded any provision for income tax or interest expense related to this

matter and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years.

Postemployment Benefits (PSCo)

PSCo adopted accrual accounting for postemployment benefits under SFAS No. 112—"Employers Accounting for Postemployment Benefits" in 1994. The costs of these benefits were historically recorded on a pay-as-you go basis and, accordingly, PSCo recorded regulatory assets in anticipation of obtaining future rate recovery of these costs. PSCo recovered its FERC jurisdictional portion of these costs. PSCo requested approval to recover its Colorado natural retail gas jurisdictional portion in a 1996 retail rate case and its retail electric jurisdictional portion in the electric earnings test filing for 1997. In the 1996 rate case, the CPUC allowed recovery of postemployment benefit costs on an accrual basis, but denied PSCo's request to amortize the regulatory asset. PSCo appealed this decision to the Denver District Court. In 1998, the CPUC deferred the final determination of the regulatory treatment of the electric jurisdictional costs pending the outcome of PSCo's appeals on the natural gas rate case. On Dec. 16, 1999, the Denver District Court affirmed the decision by the CPUC. On Jan. 31, 2000, PSCo filed a Notice of Appeal with the Colorado Supreme Court and expects a final decision on this matter during 2001. PSCo continues to believe that it will ultimately be allowed to recover this regulatory asset. If PSCo is unsuccessful in its appeal, all unrecoverable amounts totaling approximately $23 million will be written off.

Conservation Incentive Recovery (NSP-Minnesota)

In June 1999, the MPUC denied NSP-Minnesota recovery of 1998 lost margins, load management discounts and incentives associated with state-mandated programs for electric energy conservation. NSP-Minnesota recorded a $35 million charge in 1999 based on this action. NSP-Minnesota appealed the MPUC decision and in December 2000, the Minnesota Court of Appeals reversed the MPUC decision.

In January 2001, the MPUC appealed the lower court decision to the Minnesota Supreme Court. On Feb. 23, 2001, the Minnesota Supreme Court declined to hear the MPUC's appeal. NSP-Minnesota is awaiting an order from the MPUC regarding the implementation of the appeals court decision before adjusting any liabilities recorded for this matter. As of Dec. 31, 2000, NSP-Minnesota had recorded a liability of $40 million, including carrying charges, for potential refunds to customers pending the final resolution of this matter.

Leases

Xcel Energy's utility subsidiaries lease various equipment and facilities used in the normal course of business, some of which are accounted for as capital leases. Expiration of the capital leases range from 2001 to 2029, respectively. Assets acquired under capital leases are recorded as property at the lower of fair-market value or the present value of future lease payments and are amortized over their actual contract term in accordance with practices allowed by regulators. The related obligation is classified as long-term debt. Executory costs are excluded from the minimum lease payments. The net book value of property under capital leases at PSCo at year-end was approximately $54.2 million for 2000 and approximately $56.5 million for 1999.

Rental expense for Xcel Energy's utility subsidiaries is listed in the following table for 2000, 1999 and 1998, respectively (in millions of dollars). Future commitments under these leases generally decline from current levels.

	2000		1999		1998
NSP-Minnesota	$	34.3	$	33.2	$	29.6
NSP-Wisconsin	$	3.4	$	3.1	$	3.1
PSCo	$	9.6	$	10.4	$	12.2
SPS	$	2.2	$	2.3	$	2.4

Nuclear Insurance (NSP-Minnesota)

NSP-Minnesota's public liability for claims resulting from any nuclear incident is limited to $9.5 billion under the 1988 Price-Anderson amendment to the Atomic Energy Act of 1954. NSP-Minnesota has secured $200 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $9.3 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $88 million for each of its three licensed reactors to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $10 million per reactor during any one year.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $1.5 billion for each of NSP-Minnesota's two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $3 million for business interruption insurance and $11 million for property damage insurance if losses exceed accumulated reserve funds.

Fuel Contracts

The utility subsidiaries of Xcel Energy have contracts providing for the purchase and delivery of a significant portion of their current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2001 and 2017. In addition, the utility subsidiaries of Xcel Energy are required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss for the utility subsidiaries of Xcel Energy, in the form of increased costs, from market price changes in fuel is mitigated through the cost-of-energy adjustment provision of the ratemaking process, which provides for recovery of most fuel costs.

The minimum purchase for each utility subsidiary of Xcel Energy is as follows (in millions):

	Coal		Nuclear Fuel		Natural Gas
NSP	$	399	$	13	$	235
PSCo	$	822	$	0	$	471
SPS	$	891	$	0	$	0

Purchase Power Agreements

The utility subsidiaries of Xcel Energy have entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. NSP-Minnesota, PSCo and SPS have various pay-for-performance contracts with expiration dates through the year 2033. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations and energy payments based on actual power taken under the contracts. Most of the capacity and energy costs are recovered through base rates and other cost recovery mechanisms. Additionally, NSP-Minnesota, PSCo and SPS have long-term purchased power contracts with various regional utilities, expiring through 2025.

NSP-Minnesota has a 500 Mw participation power purchase commitment with the Manitoba Hydro Electric Board, which expires in 2005. The cost of this agreement is based on 80 percent of the costs of owning and operating NSP-Minnesota's Sherco 3 generating plant, adjusted to 1993 dollars. In addition, NSP-Minnesota and Manitoba Hydro have seasonal diversity exchange agreements, and there are no capacity payments for the diversity exchanges. These commitments represent about 17 percent of Manitoba Hydro's system capacity and account for approximately 10 percent of NSP-Minnesota's 2000 electric system capability. The risk of loss from nonperformance by Manitoba Hydro is not considered significant, and the risk of loss from market price changes is mitigated through cost-of-energy rate adjustments.

At Dec. 31, 2000, the estimated future payments for capacity that the utility subsidiaries of Xcel Energy are obligated to purchase, subject to availability, are as follows (in thousands):

		NSP-Minnesota*		PSCo		SPS
2001		$	110,911	$	329,927	$	16,441
2002			109,408		340,266		16,715
2003			110,379		360,778		16,995
2004			111,392		348,361		17,339
2005 and thereafter			74,760		2,628,349		341,820

	Total	$	516,850	$	4,007,681	$	409,310

*: Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Environmental Contingencies

We are subject to regulations covering air and water quality, the storage of natural gas and the storage and disposal of hazardous or toxic wastes. We continuously assess our compliance. Regulations, interpretations and enforcement policies can change, which may impact the construction and operation of, and cost of building and operating, our facilities.

Site Remediation

We must pay all or a portion of the cost to remediate sites where past activities of our subsidiaries and some other parties have caused environmental contamination. At Dec. 31, 2000, there were three categories of sites:

•: third party sites, such as landfills, to which we are alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes,
•: the site of a former federal uranium enrichment facility, and
•: sites of former manufactured gas plants (MGP's) operated by our subsidiaries or predecessors.

We record a liability when we have enough information to develop an estimate of the cost of remediating a site and revise the estimate as information is received. The estimated remediation cost may vary materially.

To estimate the cost to remediate these sites, we may have to make assumptions where facts are not fully known. For instance, we might make assumptions about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup methods and pollution control technologies, the period over which remediation will be performed and paid for, changes in environmental remediation and pollution control requirements, the potential effect of technological improvements, the number and financial strength of other potentially responsible parties and the identification of new environmental cleanup sites.

We revise our estimates as facts become known, but at Dec. 31, 2000, our estimated liability for the cost of remediating sites is detailed in the following table (in millions of dollars).

	Total Liability		Current Portion of Liability
NSP-Minnesota	$	33	$	6
NSP-Wisconsin	$	12	$	2
PSCo	$	3	$	1
SPS	$	—	$	—

Some of the cost of remediation may be recovered from others through:

•: insurance coverage;
•: recovery from other parties that have contributed to the contamination; and
•: recovery from customers.

Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined. We have recorded estimates of our share of future costs for these sites. We are not aware of any other parties' inability to pay, nor do we know if responsibility for any of the sites is in dispute.

Federal Uranium Enrichment Facility

Approximately $21 million of the long-term liability and $4 million of the current liability for NSP-Minnesota, and approximately $2 million of the long-term liability for PSCo, relate to a DOE assessment to for decommissioning a federal uranium enrichment facility. These environmental liabilities do not include accruals recorded and collected from customers in rates for future nuclear fuel disposal costs or decommissioning costs related to NSP-Minnesota's nuclear generating plants. See Note 13 to Financial Statements for further discussion of nuclear obligations.

MGP Sites

NSP-Minnesota

The MPUC allowed NSP-Minnesota to defer certain remediation costs of four active remediation sites in 1994. In September 1998, the MPUC allowed the recovery of these MGP site remediation costs in natural gas rates, with a portion assigned to NSP's electric operations for two sites formerly used by NSP generating facilities. Accordingly, NSP-Minnesota has recorded an environmental regulatory asset for these costs. NSP-Minnesota may request recovery of costs to remediate other activated sites following the completion of preliminary investigations.

NSP-Wisconsin

NSP-Wisconsin was named as one of three PRPs for creosote and coal tar contamination at a site in Ashland, Wis. The Ashland site includes property owned by NSP-Wisconsin and two other properties: an adjacent city lakeshore park area and a small area of Lake Superior's Chequemegon Bay adjoining the park.

The Wisconsin Department of Natural Resources (WDNR) and NSP-Wisconsin have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary significantly, between $4 million and $93 million, because different methods of remediation and different results are assumed in each. The EPA and WDNR are expected to select the method of remediation to use at the site during late 2001 or early 2002. Until the EPA and the WDNR select a remediation strategy for all operable units at the site and determine the level of responsibility of each PRP, we are not able to accurately estimate our share of the ultimate cost of remediating the Ashland site.

In the interim, NSP-Wisconsin has recorded a liability for an estimate of its share of the cost of remediating the portion of the Ashland site that it owns, estimated using information available to date and using reasonably effective remedial methods. NSP-Wisconsin has deferred, as a regulatory asset, the remediation costs accrued for the Ashland site because we expect that the Public Service Commission of Wisconsin (PSCW) will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs for other Wisconsin utilities.

We proposed, and the EPA and WDNR have approved, an interim action (a groundwater treatment system) for one operable unit at the site for which NSP-Wisconsin has accepted responsibility. The groundwater treatment system began operating in the fall of 2000. NSP-Wisconsin continues to work with the WDNR to access state and federal funds to apply to ultimate remediation cost of the entire site. It is probable that, even with outside funding, final remedial costs to be borne by NSP-Wisconsin will be material.

Other

Some of Xcel Energy's utility subsidiaries' facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. Since we intend to operate most of these facilities indefinitely, we can not estimate the amount or timing of payments for its final removal. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

PSCo

In January 1996, in a lawsuit by PSCo against its insurance providers, the Denver District Court entered final judgment in favor of PSCo in the amount of $5.6 million for certain cleanup costs at the Barter site in central Denver, Colo. In September 1999, the Colorado Supreme Court held that the trial court should have allocated the damages and self-insured retentions over the entire period the facilities were in operation. Although the Colorado Supreme Court remanded the judgement to the trial court for additional proceedings, it suggested that its ruling may reduce PSCo's available recovery to approximately $1.4 million. PSCo requested recovery of environmental costs of approximately $7.7 million related to Barter over four years in its proposed Performance Based Regulatory Plan for calendar years 1998-2001.

Plant Emissions

NSP-Wisconsin

In October 2000, the EPA found that NSP-Wisconsin's French Island electric generating plant should be classified as a "large municipal waste combustor" under Section 129 of the Clean Air Act. This letter was contrary to a 1997 EPA letter in which it had found that French Island should be classified as a "small combustor." The large combustor emission limits became enforceable in December 2000. NSP-Wisconsin is attempting to work with EPA to resolve the dispute regarding the status of the French Island plant. If a resolution is finalized, it may require, among other things, the installation of additional emission controls on the plant.

PSCo

In 1996, a conservation organization filed a complaint in the U. S. District Court pursuant to provisions of the Clean Air Act against the joint owners of the Craig Steam Electric Generating Station, located in western Colorado. Tri-State Generation and Transmission Association, Inc. is the operator of the Craig station and PSCo owns an undivided interest in each of two units at the station, totaling approximately 9.7 percent. In October 2000, the parties, the EPA and the Colorado Department of Public Health and Environment (CDPHE) reached an agreement in principle resolving all air quality matters related to the facility. The final agreement was negotiated during the fourth quarter of 2000 and was filed with the court on Jan. 10, 2001. The final agreement requires the installation of additional emission control equipment at a cost of approximately $105 million (based on an estimate from Tri-State). The equipment will be installed over a period of several years. In addition, the settlement requires the defendants collectively to pay a civil penalty of $500,000 and to contribute $1.5 million to fund conservation activities. The contribution to conservation activities will be refunded if the plant achieves a specified level of emissions control. The agreement will become enforceable after a period for public comment and approval by the court.

Legal Claims

In the normal course of business, Xcel Energy is a party to routine claims and litigation arising from prior and current operations. Xcel Energy is actively defending these matters and has recorded an estimate of the probable cost of settlement or other disposition.

NSP-Minnesota

On Dec. 11, 1998, a natural gas explosion in St. Cloud, Minn., killed four people, including two NSP-Minnesota employees, injured approximately 14 people and damaged several buildings. The accident occurred as a crew from Cable Constructors Inc. (CCI) was installing fiber optic cable for Seren. Seren, CCI and Sirti, an architecture/engineering firm retained by Seren, are named as defendants in 22 lawsuits relating to the explosion. NSP-Minnesota is a defendant in 19 of the lawsuits. NSP-Minnesota and Seren deny any liability for this accident. On July 11, 2000, the National Transportation Safety Board issued a report, which determined that CCI's inadequate installation procedures and delay in reporting the natural gas hit were the proximate cause of the accident. NSP-Minnesota has a self-insured retention deductible of $2 million with general liability coverage limits of $185 million. Seren's primary insurance coverage is $1 million and its secondary insurance coverage is $185 million. The ultimate cost to Xcel Energy, NSP-Minnesota and Seren, if any, is presently unknown.

13. Nuclear Obligations (NSP-Minnesota)

Fuel Disposal

NSP-Minnesota is responsible for temporarily storing used-or spent-nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from NSP's nuclear plants as well as from other U.S. nuclear plants. NSP-Minnesota has funded its portion of the DOE's permanent disposal program since 1981. The fuel disposal fees are based on a charge of 0.1 cent per kilowatt-hour sold to customers from nuclear generation. Fuel expense includes DOE fuel disposal assessments of approximately $12 million in 2000, $12 million in 1999 and $11 million in 1998. In total, NSP-Minnesota had paid approximately $284 million to the DOE through Dec. 31, 2000. However, we cannot determine whether the amount and method of the DOE's assessments to all utilities will be sufficient to fully fund the DOE's permanent storage or disposal facility.

The Nuclear Waste Policy Act required the DOE to begin accepting spent nuclear fuel no later than Jan. 31, 1998. In 1996, the DOE notified commercial spent fuel owners of an anticipated delay in accepting spent nuclear fuel by the required date and conceded that a permanent storage or disposal facility will not be available until at least 2010. NSP-Minnesota and other utilities have commenced lawsuits against the DOE to recover damages caused by the DOE's failure to meet its statutory and contractual obligations.

NSP-Minnesota has its own temporary on-site storage facilities at its Monticello and Prairie Island nuclear plants. With the dry cask storage facilities approved in 1994, management believes it has adequate storage capacity to continue operation of its Prairie Island nuclear plant until at least 2007. The Monticello nuclear plant has storage capacity to continue operations until 2010. Storage availability to permit operation beyond these dates is not assured at this time. We are investigating all of its alternatives for spent fuel storage until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent nuclear fuel as part of a consortium of electric utilities. If on-site temporary storage at Prairie Island reaches approved capacity, we could seek interim storage at this or another contracted private facility, if available.

Nuclear fuel expense includes payments to the DOE for the decommissioning and decontamination of the DOE's uranium enrichment facilities. In 1993, NSP-Minnesota recorded the DOE's initial assessment of $46 million, which is payable in annual installments from 1993-2008. NSP-Minnesota is amortizing each installment to expense on a monthly basis. The most recent installment paid in 2000 was $4 million; future installments are subject to inflation adjustments under DOE rules. NSP-Minnesota is obtaining rate recovery of these DOE assessments through the cost-of-energy adjustment clause as the assessments are amortized. Accordingly, we deferred the unamortized assessment of $28 million at Dec. 31, 2000, as a regulatory asset.

Plant Decommissioning

Decommissioning of NSP-Minnesota's nuclear facilities is planned for the years 2010-2022, using the prompt dismantlement method. We are currently following industry practice by ratably accruing the costs for decommissioning over the approved cost recovery period and including the accruals in Utility Plant—Accumulated Depreciation. Consequently, the total decommissioning cost obligation and corresponding assets currently are not recorded in Xcel Energy's financial statements.

The FASB has proposed new accounting standards that, if approved, would require the full accrual of nuclear plant decommissioning and other site exit obligations no sooner than 2002. Using Dec. 31, 2000, estimates, adoption of the proposed accounting would result in the recording of the total discounted decommissioning obligation of $838 million as a liability, with the corresponding costs capitalized as plant and other assets and depreciated over the operating life of the plant. We have not yet determined the potential impact of the FASB's proposed changes in the accounting for site exit

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obligations, such as costs of removal, other than nuclear decommissioning. However, the ultimate decommissioning and site exit costs to be accrued are expected to be similar to the current methodology. The effects of regulation are expected to minimize or eliminate any impact on operating expenses and results of operations from this future accounting change.

Consistent with cost recovery in utility customer rates, we record annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Funding presumes that current costs will escalate in the future at a rate of 4.5 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant recovery period. This annuity approach uses an assumed rate of return on funding, which is currently 5.5 percent, net of tax, for external funding and approximately 8 percent, net of tax, for internal funding.

The MPUC last approved NSP-Minnesota's nuclear decommissioning study and related nuclear plant depreciation capital recovery request in April 2000, using 1999 cost data. Although we expect to operate Prairie Island through the end of each unit's licensed life, the approved capital recovery would allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs, in 2007. This is about seven years earlier than each unit's licensed life. The approved recovery period for Prairie Island has been reduced because of the uncertainty regarding used fuel storage. We believe future decommissioning cost accruals will continue to be recovered in customer rates.

The total obligation for decommissioning currently is expected to be funded 100 percent by external funds, as approved by the MPUC. Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. The assets held in trusts as of Dec. 31, 2000, primarily consisted of investments in fixed income securities, such as tax-exempt municipal bonds and U.S. government securities that mature in 1 to 20 years, and common stock of public companies. We plan to reinvest matured securities until decommissioning begins.

At Dec. 31, 2000, NSP-Minnesota had recorded and recovered in rates cumulative decommissioning accruals of $583 million. The following table summarizes the funded status of NSP-Minnesota's decommissioning obligation at Dec. 31, 2000:

	2000
	(Thousands of dollars)
Estimated decommissioning cost obligation from most recently approved study (1999 dollars)	$	958,266
Effect of escalating costs to 2000 dollars (at 4.5 percent per year)		41,685

Estimated decommissioning cost obligation in current dollars		999,951
Effect of escalating costs to payment date (at 4.5 percent per year)		894,322

Estimated future decommissioning costs (undiscounted)		1,894,273
Effect of discounting obligation (using risk-free interest rate)		(1,056,360	)

Discounted decommissioning cost obligation		837,913
Assets held in external decommissioning trust		563,812

Discounted decommissioning obligation in excess of assets currently held in external trust	$	274,101

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Decommissioning expenses recognized include the following components:

		2000			1999			1998
		(Thousands of dollars)
Annual decommissioning cost accrual reported as depreciation expense:
	Externally funded	$	51,433		$	33,178		$	33,178
	Internally funded (including interest costs)		(16,111	)		1,595			1,477
Interest cost on externally funded decommissioning obligation			5,151			4,191			6,960
Earnings from external trust funds			(5,151	)		(4,191	)		(6,960	)

Net decommissioning accruals recorded		$	35,322		$	34,773		$	34,655

Decommissioning and interest accruals are included with the accumulated provision for depreciation on the balance sheet. Interest costs and trust earnings associated with externally funded obligations are reported in Other Income and Deductions on the income statement.

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14. Regulatory Assets and Liabilities (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Our regulated businesses prepare their financial statements in accordance with the provisions of SFAS 71, as discussed in Note 1 to the Financial Statements. Under SFAS 71, regulatory assets and liabilities can be created for amounts that regulators may allow us to collect, or may require us to pay back to customers in future electric and natural gas rates.

SFAS 71 accounting cannot be used by any portion of our business that is not rate regulated. Efforts to restructure and deregulate the utility industry have already ended our ability to apply SFAS 71 to the generation business of SPS and may further reduce or end our ability to apply SFAS 71 in the future. Write-offs and material changes to our balance sheet, income and cash flows may result.

Restructuring legislation was enacted in the SPS jurisdictions of Texas and New Mexico. See Note 10 to the Financial Statements. When the final PUCT restructuring order was issued in May 2000, SPS discontinued using SFAS 71 accounting for its electric generation business. In the second quarter of 2000, SPS' generation-related regulatory assets and other deferred costs were written off. SPS' electric transmission and distribution businesses continue to meet the requirements of SFAS 71 and are expected to remain regulated.

The components of unamortized regulatory assets and liabilities shown on the balance sheets of Xcel Energy's utility subsidiaries at December 31 are:

NSP-Minnesota

		Remaining Amortization Period	2000		1999
			(Thousands of dollars)
AFDC recorded in plant(a)		Plant Lives	$	96,466	$	104,958
Conservation programs(a)		Up to 5 Years		12,948		0
Losses on reacquired debt		Term of Related Debt		39,629		41,450
Environmental costs		Primarily 9 Years		34,237		37,548
Unrecovered gas costs(b)		1-2 Years		24,213		14,956
Renewable resource costs		Undetermined		10,500		0
State commission accounting adjustments(a)		Plant Lives		4,977		5,247
Other		Various		3,577		4,017

	Total regulatory assets		$	226,547	$	208,176

Investment tax credit deferrals			$	61,111	$	66,698
Unrealized gains from decommissioning investments				171,736		177,578
Pension costs-regulatory differences				139,178		84,198
Conservation incentives				40,679		25,284
Deferred income tax adjustments				74,697		70,916
Fuel costs, refunds and other				8,912		15,043

	Total regulatory liabilities		$	496,313	$	439,717

(a): Earns a return on investment in the ratemaking process.
(b): Excludes current portion with expected rate recovery within 12 months of $13 million and $8 million for 2000 and 1999, respectively.

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NSP-Wisconsin

			Remaining Amortization Period	2000		1999
				(Thousands of dollars)
AFDC recorded in plant(c)			Plant Lives	$	7,032	$	7,333
Conservation programs(c)			Through 2003		3,321		5,254
Losses on reacquired debt			Term of Related Debt		10,608		11,248
Environmental costs			Undetermined		13,358		11,161
State commission accounting adjustments(c)			Plant Lives		2,637		2,393
Other			Various		1,580		1,863

	Total regulatory assets			$	38,536	$	39,252

Investment tax credit deferrals				$	11,050	$	11,583
Deferred income tax adjustments					5,572		6,390
Fuel costs, refunds and other					2,196		3,753

		Total regulatory liabilities		$	18,818	$	21,726

(c): Earns a return on investment in the ratemaking process.

PSCo

		Remaining Amortization Period	2000		1999
			(Thousands of dollars)
AFDC recorded in plant(d)		Plant Lives	$	40,779	$	42,811
Conservation programs(d)		Up to 5 Years		20,728		24,211
Losses on reacquired debt		Term of Related Debt		16,242		14,284
Deferred income tax adjustments		Mainly Plant Lives		44,885		70,852
Nuclear decommissioning costs		5 Years		54,267		63,835
Employees' postretirement benefits other than pension		12 Years		46,680		50,570
Employees' postemployment benefits		Undetermined		23,018		23,018
Other		Various		4,555		1,322

	Total regulatory assets (e)		$	251,154	$	290,903

Investment tax credit deferrals			$	45,027	$	54,652

	Total regulatory liabilities		$	45,027	$	54,652

(d): Earns a return on investment in the ratemaking process.
(e): Excludes deferred energy charges expected to be recovered within the next 12 months of $159 million for 2000 and $43 million for 1999.

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SPS

		Remaining Amortization Period	2000		1999
			(Thousands of dollars)
AFDC recorded in plant(f)		Plant Lives	$	15,027	$	29,662
Conservation programs(f)		Up to 5 Years		15,446		11,403
Losses on reacquired debt		Term of Related Debt		18,697		16,671
Deferred income tax adjustments		Mainly Plant Lives		23,136		35,225
Employees' postretirement benefits other than pension				0		2,751
Other		Various		2,053		8,491

	Total regulatory assets (g)		$	74,359	$	104,203

Investment tax credit deferrals			$	1,275	$	2,785

	Total regulatory liabilities		$	1,275	$	2,785

(f): Earns a return on investment in the ratemaking process.
(g): Excludes deferred energy charges expected to be recovered within the next 12 months of $104 million for 2000 and $2 million for 1999.

15. Segment and Related Information (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Xcel Energy's utility subsidiaries have two reportable segments: Electric Utility and Gas Utility.

•: Xcel Energy's Electric Utility generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas, New Mexico, Wyoming, Kansas and Oklahoma. It also makes sales for resale and provides wholesale transmission service to various entities in the United States. Electric Utility also includes PSCo's electric trading operations.
•: Xcel Energy's Gas Utility transmits, transports, stores and distributes natural gas and propane primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan, Arizona, Colorado and Wyoming.

Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the All Other category.

To report net income for electric and natural gas utility segments, Xcel Energy must assign or allocate all costs and certain other income. In general, costs are:

•: directly assigned wherever applicable
•: allocated based on cost causation allocators wherever applicable
•: allocated based on a general allocator for all other costs not assigned by the above two methods.

The accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies. Xcel Energy evaluates performance by each legal entity based on profit or loss.

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Business Segments

NSP-Minnesota

*2000*		Electric Utility		Gas Utility		All Other		Reconciling Eliminations		Consolidated Total
		(Thousands of dollars)
Operating revenues from external customers		$	2,411,197	$	535,131		—		—	$	2,946,328
Intersegment revenues			686		1,569		—		—		2,255

	Total revenues		2,411,883		536,700		—		—		2,948,583
Depreciation and Amortization			300,961		22,945		29		—		323,935
Financing costs, mainly interest exp.			129,298		12,918		169		—		142,385
Income tax expense			83,718		8,364		109		—		92,191

Segment net income		$	90,363	$	19,538	$	1,323	$	—	$	111,224

*1999*		Electric Utility		Gas Utility		All Other		Reconciling Eliminations		Consolidated Total
		(Thousands of dollars)
Operating revenues from external customers		$	2,266,521	$	364,340		—		—	$	2,630,861
Intersegment revenues			692		1,495		—		—		2,187

	Total revenues		2,267,213		365,835		—		—		2,633,048
Depreciation and Amortization			286,894		23,235		—		—		310,129
Financing costs, mainly interest exp.			106,815		12,721		1,238		—		120,774
Income tax expense			93,866		2,285		1,280		—		97,431

Segment net income		$	145,906	$	11,200	$	1,874	$	—	$	158,980

*1998*		Electric Utility		Gas Utility		All Other		Reconciling Eliminations		Consolidated Total
		(Thousands of dollars)
Operating revenues from external customers		$	2,243,125	$	355,847		—		—	$	2,598,972
Intersegment revenues			648		4,721		—		—		5,369

	Total revenues		2,243,773		360,568		—		—		2,604,341
Depreciation and Amortization			274,953		21,106		—		—		296,059
Financing costs, mainly interest exp.			93,878		11,071		1,423		—		106,372
Income tax expense			117,044		6,578		1,091		—		124,713

Segment net income		$	196,258	$	12,259	$	1,689	$	—	$	210,206

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NSP-Wisconsin

*2000*		Electric Utility		Gas Utility		All Other		Reconciling Eliminations		Consolidated Total
		(Thousands of dollars)
Operating revenues from external customers		$	424,312	$	108,077		—		—	$	532,389
Intersegment revenues			165		1,946		—		—		2,111

	Total revenues		424,477		110,023		—		—		534,500
Depreciation and Amortization			35,103		5,399		—		—		40,502
Financing costs, mainly interest exp.			17,019		2,236		—		—		19,255
Income tax expense			18,287		2,403		—		—		20,690

Segment net income		$	26,723	$	3,573	$	—	$	—	$	30,296

*1999*		Electric Utility		Gas Utility		All Other		Reconciling Eliminations		Consolidated Total
		(Thousands of dollars)
Operating revenues from external customers		$	411,391	$	79,500		—		—	$	490,891
Intersegment revenues			141		2,875		—		—		3,016

	Total revenues		411,532		82,375		—		—		493,907
Depreciation and Amortization			35,964		6,153		—		—		42,117
Financing costs, mainly interest exp.			16,904		1,626		—		—		18,530
Income tax expense			22,733		2,569		—		—		25,302

Segment net income		$	32,959	$	3,407	$	—	$	—	$	36,366

*1998*		Electric Utility		Gas Utility		All Other		Reconciling Eliminations		Consolidated Total
		(Thousands of dollars)
Operating revenues from external customers		$	398,330	$	74,274		—		—	$	472,604
Intersegment revenues			167		4,571		—		—		4,738

	Total revenues		398,497		78,845		—		—		477,342
Depreciation and Amortization			33,463		5,672		—		—		39,135
Financing costs, mainly interest exp.			17,089		1,590		—		—		18,679
Income tax expense			18,868		1,600		—		—		20,468

Segment net income		$	30,094	$	2,101	$	—	$	—	$	32,195

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PSCo

*2000*		Electric Utility		Gas Utility		All Other			Reconciling Eliminations			Consolidated Total
		(Thousands of dollars)
Operating revenues from external customers		$	2,827,181	$	787,110	$	10,845			—		$	3,625,136
Intersegment revenues			—		—		—			—			—

	Total revenues		2,827,181		787,110		10,845			—			3,625,136
Depreciation and Amortization			156,896		51,636		2,172			—			210,704
Financing costs, mainly interest exp.			122,859		40,448		20,808			(22,824	)		161,291
Income tax expense (credit)			100,679		22,313		(20,222	)		—			102,770

Segment net income		$	134,425	$	28,795	$	32,908		$	—		$	196,128

*1999*		Electric Utility		Gas Utility		All Other			Reconciling Eliminations			Consolidated Total
		(Thousands of dollars)
Operating revenues from external customers		$	2,040,383	$	657,822	$	8,045			—		$	2,706,250
Intersegment revenues			—		—		—			—			—

	Total revenues		2,040,383		657,822		8,045			—			2,706,250
Depreciation and Amortization			145,945		46,401		2,019			—			194,365
Financing costs, mainly interest exp.			115,607		35,301		19,010			(13,744	)		156,174
Income tax expense (credit)			95,743		15,717		(14,886	)		—			96,574

Segment net income		$	155,330	$	29,289	$	19,646		$	—		$	204,265

*1998*		Electric Utility		Gas Utility		All Other			Reconciling Eliminations			Consolidated Total
		(Thousands of dollars)
Operating revenues from external customers		$	1,635,573	$	640,064	$	8,348			—		$	2,283,985
Intersegment revenues			—		—		—			—			—

	Total revenues		1,635,573		640,064		8,348			—			2,283,985
Depreciation and Amortization			135,876		43,036		2,001			—			180,913
Financing costs, mainly interest exp.			89,544		26,489		14,442			7,839			138,314
Income tax expense (credit)			97,924		13,997		(10,427	)		—			101,494

Segment net income (loss)		$	170,101	$	30,463	$	17,855		$	(18,316	)	$	200,103

SPS

SPS operates in the regulated electric utility industry providing wholesale and retail electric service in the states of Texas, New Mexico, Kansas and Oklahoma. Revenues from external customers were $1,079.6 million, $925.9 million and $951.2 million for the years ended Dec. 31, 2000, 1999 and 1998, respectively.

108

16. Summarized Quarterly Financial Data (Unaudited) (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

NSP-Minnesota

	Quarter Ended
	March 31, 2000		June 30, 2000		Sept. 30, 2000(a)		Dec. 31, 2000(a)
	(Thousands of dollars)
Revenue	$	713,517	$	633,382	$	761,031	$	840,653
Operating income		80,757		79,443		94,724		100,760
Net income		30,237		26,871		25,163		28,953

	Quarter Ended
	March 31, 1999		June 30, 1999(b)		Sept. 30, 1999		Dec. 31, 1999(b)
	(Thousands of dollars)
Revenue	$	666,458	$	584,084	$	767,244	$	615,262
Operating income		92,032		38,366		160,911		86,946
Net income		41,471		6,663		79,250		31,596

(a): 2000 results include special charges related to merger costs and strategic alignment as discussed in Note 2 to the Financial Statements. Third quarter results were reduced by approximately $59 million. Fourth quarter results were reduced by approximately $13 million.
(b): 1999 results include two adjustments related to regulatory recovery of conservation program incentives. Second quarter results were reduced by $35 million before taxes due to the disallowance of 1998 incentives. Fourth quarter results were reduced by $22 million before taxes due to the reversal of all income recorded through the third quarter for 1999 electric conservation program incentives.

NSP-Wisconsin

	Quarter Ended
	March 31, 2000		June 30, 2000		Sept. 30, 2000(a)		Dec. 31, 2000(a)
	(Thousands of dollars)
Revenue	$	144,454	$	113,501	$	121,702	$	154,843
Operating income		25,819		10,250		9,924		23,317
Net income		12,751		4,044		1,843		11,658

	Quarter Ended
	March 31, 1999		June 30, 1999		Sept. 30, 1999		Dec. 31, 1999
	(Thousands of dollars)
Revenue	$	137,576	$	108,464	$	117,978	$	129,889
Operating income		27,781		10,556		16,050		25,506
Net income		13,727		3,777		6,864		11,998

(a): 2000 results include special charges related to merger costs and strategic alignment as discussed in Note 2 to the Financial Statements. Third quarter results were reduced by approximately $11 million. Fourth quarter results were reduced by approximately $2 million.

109

PSCo

	Quarter Ended
	March 31, 2000		June 30, 2000		Sept. 30, 2000(a)		Dec. 31, 2000(a)
	(Thousands of dollars)
Revenue(b)	$	722,434	$	676,061	$	943,634	$	1,283,007
Operating income		142,231		124,466		59,705		126,436
Net income		68,759		60,921		7,847		58,601

	Quarter Ended
	March 31, 1999		June 30, 1999		Sept. 30, 1999		Dec. 31, 1999
	(Thousands of dollars)
Revenue(b)	$	659,419	$	558,457	$	651,064	$	837,310
Operating income		130,022		85,565		112,919		123,537
Net income		65,939		34,820		49,749		53,757

(a): 2000 results include special charges related to merger costs and strategic alignment as discussed in Note 2 to the Financial Statements. Third quarter results were reduced by approximately $63 million. Fourth quarter results were reduced by approximately $14 million.
(b): Trading revenues have been reclassified to reflect presentation on a gross basis for all periods.

SPS

	Quarter Ended
	March 31, 2000		June 30, 2000			Sept. 30, 2000(a)			Dec. 31, 2000(a)
	(Thousands of dollars)
Revenue	$	216,232	$	256,643		$	319,530		$	287,175
Operating income		41,081		58,042			67,941			32,257
Income before extraordinary items		18,256		28,646			31,891			9,659
Extraordinary items		—		(13,658	)		(5,302	)		—
Net income		18,256		14,988			26,589			9,659

	Quarter Ended
	March 31, 1999		June 30, 1999		Sept. 30, 1999		Dec. 31, 1999
	(Thousands of dollars)
Revenue	$	202,552	$	224,114	$	290,587	$	208,684
Operating income		49,734		49,955		80,933		33,551
Net income		23,391		22,835		42,534		13,949

(a): 2000 results include special charges related to merger costs and strategic alignment as discussed in Note 2 to the Financial Statements. Third quarter results were reduced by approximately $20 million. Fourth quarter results were reduced by approximately $4 million.

17. Related Party Transactions (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

NSP-Minnesota, NSP-Wisconsin, PSCo and SPS receive various administrative, management, environmental and other support services from Xcel Services which began operations in August 2000. Prior to this, all of these support services resided in Former NSP for NSP-Minnesota and NSP-Wisconsin and were allocated to the former NSP subsidiaries, as appropriate. New Century Services provided these support services to PSCo and SPS prior to the merger.

110

NSP-Minnesota

One of Xcel's subsidiaries, Viking Gas Transmission Company (Viking), transports gas purchased by NSP-Minnesota from various suppliers. Under various contracts and agreements with Viking, which extend through 2008, NSP-Minnesota incurred transportation costs of $5.5 million in 2000, $3.8 million in 1999 and $3.4 million in 1998 for gas purchased through Viking, which is an affiliate company to NSP-Minnesota.

NSP-Minnesota and NSP-Wisconsin

The electric production and transmission costs of the entire NSP system are shared by NSP-Minnesota and NSP-Wisconsin. A FERC approved agreement (Interchange Agreement) between the two companies provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs. Billings under the Interchange Agreement which are included in the Statements of Income are as follows (in thousands of dollars).

			2000		1999		1998
NSP-Minnesota
Operating revenues:
	Electric
		Production related	$	200,522	$	192,069	$	190,282
		Transmission		16,600		15,366		15,963
	Gas			220		192		213
Operating expenses:
	Purchased and interchange power			45,294		48,193		48,165
	Gas purchased for resale			608		0		45
	Other operations			28,131		26,021		25,529

		2000			1999		1998
NSP-Wisconsin
Operating revenues:
	Electric	$	73,425		$	74,214	$	73,674
	Gas		0			0		45
Operating expenses (income):
	Purchased and interchange power		199,730			192,541		190,019
	Gas purchased for resale		220			192		213
	Other operations		(179	)		18,212		15,066

NSP-Wisconsin obtains short-term borrowings from NSP-Minnesota at NSP-Minnesota's average daily interest rate, including the cost of NSP-Minnesota's compensating balance requirements. Interest charges on NSP-Wisconsin's statement of income and other income on NSP-Minnesota's statement of income include $3.4 million, $2.5 million and $2.0 million for 2000, 1999 and 1998, respectively, related to this.

NSP-Minnesota's receivables from affiliates includes amounts receivable from NSP-Wisconsin for the interchange agreement and short-term borrowings. NSP-Minnesota's payable to affiliates primarily represents amounts payable to Xcel Services for NSP-Minnesota's allocation of support services from Xcel Services.

NSP-Wisconsin's payable to affiliates primarily represents amounts payable to NSP-Minnesota for the interchange agreement and short-term borrowings.

111

PSCo and SPS

PSCo and SPS receive construction services from UE. In addition, PSCo and SPS pay interest expense on any short-term borrowings from Xcel Energy.

PSCo sells firm and interruptible transportation services to e prime for gas delivered into the Denver/Pueblo operating area. PSCo purchases gas from e prime to service customers in the Denver/Pueblo operating area. PSCo also receives interest income from Xcel International on the note receivable related to the sale of New Century International effective March 31, 1998. SPS receives interest income from Xcel Energy Wholesale Energy Group Inc. on the note receivable related to the sale of Quixx and UE as part of the PSCo/SPS Merger. The table below contains the various significant affiliate transactions among the companies and related parties for the years ended Dec. 31, 2000, 1999 and 1998 (in thousands).

	PSCo						SPS
	2000		1999		1998		2000		1999		1998
Gas revenues	$	8,750	$	7,416	$	5,281	$	—	$	—	$	—
Cost of gas sold		49,383		2,102		—		—		—		—
Operating expenses		500,954		166,619		197,862		210,174		68,866		63,108
Interest income		10,377		13,494		14,188		8,640		8,620		8,630
Interest expenses		3,952		4,146		1,714		850		790		1,390
Construction services		67,893		110,004		68,744		7,397		8,970		6,465

112

Item 9—Changes in and Disagreements with Accountants on Accounting and Financial Disclosure (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

During 2000, there were no disagreements with the independent public accountants for NSP-Minnesota, NSP-Wisconsin, PSCo and SPS on accounting procedures or accounting and financial disclosures.

NSP-Minnesota

On Aug. 18, 2000, New Century Energies, Inc. (NCE) and Northern States Power Co. (NSP) merged and formed Xcel Energy Inc. 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 Company (NSP-Minnesota). Prior to the merger, PricewaterhouseCoopers LLP served as the accountants for NSP. As discussed in Xcel Energy's Form 8-K filed on Aug. 21, 2000, in connection with the merger, Xcel Energy's management informed PricewaterhouseCoopers LLP that the firm would no longer be engaged as principal independent accountants for Xcel Energy. On Aug. 18, 2000, the Audit Committee of Xcel Energy's Board of Directors recommended, and the Xcel Energy Board approved, the decision to engage Arthur Andersen LLP as its new principal independent accountants for Xcel Energy and its utility subsidiaries for 2000. As part of this decision, Arthur Andersen was engaged for 2000 as the principal independent accountants for the newly-formed NSP-Minnesota. However, because PricewaterhouseCoopers had served as NSP's accountants through 1999, and because NSP-Minnesota's assets following the merger consisted of the utility operations of NSP prior to the merger, PricewaterhouseCoopers was engaged for the limited purpose of auditing NSP-Minnesota's 1999 financial statements that were included in NSP-Minnesota's Form 10 filed with the SEC on Oct. 3, 2000. There were no disagreements with PricewaterhouseCoopers regarding their prior audits of NSP or their audit of NSP-Minnesota's 1999 financial statements.

NSP-Wisconsin

As discussed in NSP-Wisconsin's Form 8-K filed on Aug. 23, 2000, in connection with the merger, Xcel Energy's management informed PricewaterhouseCoopers LLP that the firm would no longer be engaged as principal independent accountants for NSP-Wisconsin. As discussed in NSP-Wisconsin's Form 8-K filed on Aug, 31, 2000, on Aug. 28, 2000, the NSP-Wisconsin Board of Directors appointed Arthur Andersen LLP as its new principal independent accountants.

PART III

Part III of Form 10-K has been omitted from this report for Xcel Energy's utility subsidiaries in accordance with conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries.

Item 10—Directors and Executive Officers of the Registrant (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Item 11—Executive Compensation (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Item 12—Security Ownership of Certain Beneficial Owners and Management (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Item 13—Certain Relationships and Related Transactions (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

113

PART IV

Item 14—Exhibits, Financial Statement Schedules and Reports on Form 8-K

(NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

NSP-Minnesota

(a)	1.		Financial Statements and Schedules		Page
			Included in Part II of this report:
			Reports of Independent Accountants for the years ended Dec. 31, 2000, 1999, and 1998.		xx
			Statements of Income for the three years ended Dec. 31, 2000.		xx
			Statements of Cash Flows for the three years ended Dec. 31, 2000.		xx
			Balance Sheets, Dec. 31, 2000 and 1999.		xx
			Notes to Financial Statements.		xx

Exhibits

*: Indicates incorporation by reference.

			2.01*		Agreement and Plan of Merger, dated as of March 24, 1999, by and between Northern States Power Company and New Century Energies, Inc. (Incorporated by reference to Exhibit 2.1 to the Report on Form 8-K (File No. 1-12907) of New Century Energies, Inc. dated March 24, 1999.)
			3.01*		Articles of Incorporation and Amendments of the Company.
			3.02*		By-Laws of the Company.
			4.01*		Trust Indenture, dated Feb. 1, 1937, from NSP to Harris Trust and Savings Bank, as Trustee. (Exhibit B-7 to File No. 2-5290.)
			4.02*		Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP to Harris Trust and Savings Bank, as Trustee. (Exhibit 4.02 to Form 10-K of NSP for the year 1988, File No. 1-3034.)
					Supplemental Indenture between NSP and said Trustee, supplemental to Exhibit 4.01, dated as follows:
			4.03*		June 1, 1942 (Exhibit B-8 to File No. 2-97667).
			4.04*		Feb. 1, 1944 (Exhibit B-9 to File No. 2-5290).
			4.05*		Oct. 1, 1945 (Exhibit 7.09 to File No. 2-5924).
			4.06*		July 1, 1948 (Exhibit 7.05 to File No. 2-7549).
			4.07*		Aug. 1, 1949 (Exhibit 7.06 to File No. 2-8047).
			4.08*		June 1, 1952 (Exhibit 4.08 to File No. 2-9631).
			4.09*		Oct. 1, 1954 (Exhibit 4.10 to File No. 2-12216).
			4.10*		Sept. 1, 1956 (Exhibit 2.09 to File No. 2-13463).
			4.11*		Aug. 1, 1957 (Exhibit 2.10 to File No. 2-14156).

114

			4.12*		July 1, 1958 (Exhibit 4.12 to File No. 2-15220).
			4.13*		Dec. 1, 1960 (Exhibit 2.12 to File No. 2-18355).
			4.14*		Aug. 1, 1961 (Exhibit 2.13 to File No. 2-20282).
			4.15*		June 1, 1962 (Exhibit 2.14 to File No. 2-21601).
			4.16*		Sept. 1, 1963 (Exhibit 4.16 to File No. 2-22476).
			4.17*		Aug. 1, 1966 (Exhibit 2.16 to File No. 2-26338).
			4.18*		June 1, 1967 (Exhibit 2.17 to File No. 2-27117).
			4.19*		Oct. 1, 1967 (Exhibit 2.01R to File No. 2-28447).
			4.20*		May 1, 1968 (Exhibit 2.01S to File No. 2-34250).
			4.21*		Oct. 1, 1969 (Exhibit 2.01T to File No. 2-36693).
			4.22*		Feb. 1, 1971 (Exhibit 2.01U to File No. 2-39144).
			4.23*		May 1, 1971 (Exhibit 2.01V to File No. 2-39815).
			4.24*		Feb. 1, 1972 (Exhibit 2.01W to File No. 2-42598).
			4.25*		Jan. 1, 1973 (Exhibit 2.01X to File No. 2-46434).
			4.26*		Jan. 1, 1974 (Exhibit 2.01Y to File No. 2-53235).
			4.27*		Sept. 1, 1974 (Exhibit 2.01Z to File No. 2-53235).
			4.28*		April 1, 1975 (Exhibit 4.01AA to File No. 2-71259).
			4.29*		May 1, 1975 (Exhibit 4.01BB to File No. 2-71259).
			4.30*		March 1, 1976 (Exhibit 4.01CC to File No. 2-71259).
			4.31*		June 1, 1981 (Exhibit 4.01DD to File No. 2-71259).
			4.32*		Dec. 1, 1981 (Exhibit 4.01EE to File No. 2-83364).
			4.33*		May 1, 1983 (Exhibit 4.01FF to File No. 2-97667).
			4.34*		Dec. 1, 1983 (Exhibit 4.01GG to File No. 2-97667).
			4.35*		Sept. 1, 1984 (Exhibit 4.01HH to File No. 2-97667).
			4.36*		Dec. 1, 1984 (Exhibit 4.01II to File No. 2-97667).
			4.37*		May 1, 1985 (Exhibit 4.36 to Form 10-K for the year 1985, File No. 1-3034).
			4.38*		Sept. 1, 1985 (Exhibit 4.37 to Form 10-K for the year 1985, File No. 1-3034).
			4.39*		July 1, 1989 (Exhibit 4.01 to Form 8-K dated July 7, 1989, File No. 1-3034).
			4.40*		June 1, 1990 (Exhibit 4.01 to Form 8-K dated June 1, 1990, File No. 1-3034).
			4.41*		Oct. 1, 1992 (Exhibit 4.01 to Form 8-K dated Oct. 13, 1992, File No. 1-3034).
			4.42*		April 1, 1993 (Exhibit 4.01 to Form 8-K dated March 30, 1993, File No. 1-3034).
			4.43*		Dec. 1, 1993 (Exhibit 4.01 to Form 8-K dated Dec. 7, 1993, File No. 1-3034).
			4.44*		Feb. 1, 1994 (Exhibit 4.01 to Form 8-K dated Feb. 10, 1994, File No. 1-3034).
			4.45*		Oct. 1, 1994 (Exhibit 4.01 to Form 8-K dated Oct. 5, 1994, File No. 1-3034).

115

			4.46*		June 1, 1995 (Exhibit 4.01 to Form 8-K dated June 28, 1995, File No. 1-3034).
			4.47*		April 1, 1997 (Exhibit 4.47 to Form 10-K for the year 1997, File No. 1-3034).
			4.48*		March 1, 1998 (Exhibit 4.01 to Form 8-K dated March 11, 1998, File No. 1-3034).
			4.49*		May 1, 1999
			4.50*		June 1, 2000
			4.51*		Aug. 1, 2000 (Assignment and Assumption of Trust Indenture)
			4.52*		Subordinated Debt Securities Indenture, dated as of Jan. 30, 1997, between Xcel Energy and Norwest Bank Minnesota, National Association, as trustee. (Exhibit 4.02 to Form 8-K dated Jan. 28, 1997, File No. 001-03034.)
			4.53*		Preferred Securities Guarantee Agreement, dated as of Jan. 31, 1997, between Xcel Energy and Wilmington Trust Company, as Trustee. (Exhibit 4.05 to Form 8-K dated Jan. 28, 1997, File No. 001-03034.)
			4.54*		Preferred Securities Guarantee Agreement, dated as of Aug. 18, 2000, between Northern States Power Company and Wilmington Trust Company, as Trustee.
			4.55*		Amended and Restated Declaration of Trust of NSP Financing I, dated as of Jan. 31, 1997, including form of Preferred Security. (Exhibit 4.10 to Form 8-K dated Jan. 28, 1997, File No. 001-03034.)
			4.56*		Supplemental Indenture, dated as of Jan. 31, 1997, between Xcel Energy and Norwest Bank Minnesota, National Association, as trustee, including form of Junior Subordinated Debenture. (Exhibit 4.12 to Form 8-K dated Jan. 28, 1997, File No. 001-03034.)
			4.57*		Supplemental Trust Indenture dated Aug. 18, 2000 between Xcel Energy, Northern States Power Company and Wells Fargo Bank Minnesota, National Association, as Trustee
			4.58*		Common Securities Guarantee Agreement dated as of Jan. 31, 1997, between Xcel Energy and Wilmington Trust Company, as Trustee. (Exhibit 4.13 to Form 8-K dated Jan. 28, 1997, File No. 001-03034.)
			4.59*		Common Securities Guarantee Agreement dated as of Aug. 18, 2000, between NSP and Wilmington Trust Company, as Trustee.
			4.60*		Subscription Agreement, dated as of Jan. 28, 1997, between NSP Financing I and NSP. (Exhibit 4.14 to Form 8-K dated Jan. 28, 1997, File No. 001-03034.)
			4.61*		Trust Indenture, dated July 1, 1999, between NSP and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to Form 8-K dated July 21, 1999, File No. 1-03034.)
			4.62*		Supplemental Trust Indenture, dated July 15, 1999, between NSP and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.02 to Form 8-K dated July 21, 1999, File No. 1-03034.)
			4.63*		Supplemental Trust Indenture, dated Aug. 18, 2000, among Xcel Energy, Northern States Power Company and Wells Fargo Bank Minnesota, National Association, as Trustee.

116

	10.01*	Facilities Agreement, dated July 21, 1976, between NSP and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kilovolt (kv) line. (Exhibit 5.06I to File No. 2-54310.)
	10.02*	Transactions Agreement, dated July 21, 1976, between NSP and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kv line. (Exhibit 5.06J to File No. 2-54310.)
	10.03*	Coordinating Agreement, dated July 21, 1976, between NSP and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kv line. (Exhibit 5.06K to File No. 2-54310.)
	10.04*	Ownership and Operating Agreement, dated March 11, 1982, between NSP, Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3. (Exhibit 10.01 to Form 10-Q for the quarter ended Sept. 30, 1994, File No. 1-3034.)
	10.05*	Transmission Agreement, dated April 27, 1982, and Supplement No. 1, dated July 20, 1982, between NSP and Southern Minnesota Municipal Power Agency. (Exhibit 10.02 to Form 10-Q for the quarter ended Sept. 30, 1994, File No. 1-3034.)
	10.06*	Power Agreement, dated June 14, 1984, between NSP and the Manitoba Hydro-Electric Board, extending the agreement scheduled to terminate on April 30, 1993, to April 30, 2005. (Exhibit 10.03 to Form 10-Q for the quarter ended Sept. 30, 1994, File No. 1-3034.)
	10.07*	Power Agreement, dated August 1988, between NSP and Minnkota Power Company. (Exhibit 10.08 to Form 10-K for the year 1988, File No. 1-3034.)
	10.08*	Assignment and Assumption Agreement, dated Aug. 18, 2000 between Northern States Power Company and Xcel Energy Inc.
	12.01	Statement of Computation of Ratio of Earnings to Fixed Charges
	16.01*	Letter regarding change in accountant (Exhibit 16 to Xcel Energy Form 8-K dated Aug. 21, 2000, File No. 1-3034)
	99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995
(b) Reports on Form 8-K — The following report on Form 8-K was filed either during the three months ended Dec. 31, 2000, or between Dec. 31, 2000 and the date of this report. None

NSP-Wisconsin

(a)	1.		Financial Statements and Schedules		Page
			Included in Part II of this report:
			Report of Independent Accountants for the years ended Dec. 31, 2000, 1999, and 1998.		xx
			Statements of Income for the three years ended Dec. 31, 2000.		xx
			Statements of Cash Flows for the three years ended Dec. 31, 2000.		xx
			Balance Sheets, Dec. 31, 2000 and 1999.		xx
			Notes to Financial Statements.		xx

117

Exhibits

*: indicates incorporation by reference.

			3.01*		Restated Articles of Incorporation as of Dec. 23, 1987. (Filed as Exhibit 3.01 to Form 10-K Report 10-3140 for the year 1987)
			3.02*		Copy of the By-Laws of NSP-Wisconsin as amended Feb. 2, 2000
			4.01*		Copy of Trust Indenture, dated April 1, 1947, From NSP-Wisconsin to Firstar Trust Company (formerly First Wisconsin Trust Company). (Filed as Exhibit 7.01 to Registration Statement 2-6982)
			4.02*		Copy of Supplemental Trust Indenture, dated March 1, 1949. (Filed as Exhibit 7.02 to Registration Statement 2-7825)
			4.03*		Copy of Supplemental Trust Indenture, dated June 1, 1957. (Filed as Exhibit 2.13 to Registration Statement 2-13463)
			4.04*		Copy of Supplemental Trust Indenture, dated Aug. 1, 1964. (Filed as Exhibit 4.20 to Registration Statement 2-23726)
			4.05*		Copy of Supplemental Trust Indenture, dated Dec. 1, 1969. (Filed as Exhibit 2.03E to Registration Statement 2-36693)
			4.06*		Copy of Supplemental Trust Indenture, dated Sept. 1, 1973. (Filed as Exhibit 2.03F to Registration Statement 2-49757)
			4.07*		Copy of Supplemental Trust Indenture, dated Feb. 1, 1982. (Filed as Exhibit 4.01G to Registration Statement 2-76146)
			4.08*		Copy of Supplemental Trust Indenture, dated March 1, 1982. (Filed as Exhibit 4.08 to form 10-K Report 10-3140 for the year 1982)
			4.09*		Copy of Supplemental Trust Indenture, dated June 1, 1986. (Filed as Exhibit 4.09 to Form 10-K Report 10-3140 for the year 1986)
			4.10*		Copy of Supplemental Trust Indenture, dated March 1, 1988. (Filed as Exhibit 4.10 to Form 10-K Report 10-3140 for the year 1988)
			4.11*		Copy of Supplemental and Restated Trust Indenture, dated March 1, 1991. (Filed as Exhibit 4.01K to Registration Statement 33-39831)
			4.12*		Copy of Supplemental Trust Indenture, dated April 1, 1991. (Filed as Exhibit 4.01 to Form 10-Q Report 10-3140 for the quarter ended March 31, 1991)
			4.13*		Copy of Supplemental Trust Indenture, dated March 1, 1993. (Filed as Exhibit to Form 8-K Report dated March 3, 1993)
			4.14*		Copy of Supplemental Trust Indenture, dated Oct. 1, 1993. (Filed as Exhibit 4.01 to Form 8-K Report dated Sept. 21, 1993)
			4.15*		Copy of Supplemental Trust Indenture, dated Dec. 1, 1996. (Filed as Exhibit 4.01 to Form 8-K Report dated Dec. 12, 1996)
			10.01*		Copy of Interchange Agreement dated Sept. 17, 1984, and Settlement Agreement dated May 31, 1985, between NSP-Wisconsin, the Minnesota Company and LSDP. (Filed as Exhibit 10.10 to Form 10-K Report 10-3140 for the year 1985)
			12.01		Statement of Computation of Ratio of Earnings to Fixed Charges

118

	16.01*	Letter regarding change in accountant (Exhibit 16 to NSP-Wisconsin Form 8-K dated August 23, 2000, File No. 1-3140)
	99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
(b) Reports on Form 8-K — The following report on Form 8-K was filed either during the three months ended Dec. 31, 2000, or between Dec. 31, 2000 and the date of this report. None

PSCo

(a)	1.		Financial Statements and Schedules		Page
			Included in Part II of this report:
			Report of Independent Accountants for the years ended Dec. 31, 2000, 1999, and 1998.		xx
			Statements of Income for the three years ended Dec. 31, 2000.		xx
			Statements of Cash Flows for the three years ended Dec. 31, 2000.		xx
			Balance Sheets, Dec. 31, 2000 and 1999.		xx
			Notes to Financial Statements.		xx

Exhibits

*: indicates incorporation by reference.

			2.01*		Merger Agreement and Plan of Reorganization dated Aug. 22, 1995 (Form 8-K, dated Aug. 22, 1995, File No. 1-3280 — Exhibit 2).
			3.01*		Amended and Restated Articles of Incorporation dated July 10, 1998 (Form 10-K, Dec. 31, 1998, Exhibit 3(a)(1)).
			3.02*		By-laws dated Nov. 20, 1997 (Form 10-K, Dec. 31, 1997, Exhibit 3(b)(1)).
			4.01*		Indenture, dated as of Dec. 1, 1939, providing for the issuance of First Mortgage Bonds (Form 10 for 1946- Exhibit (B-1)).

119


			4.02*		Indentures supplemental to Indenture dated as of Dec. 1, 1939:

Dated as of	Previous Filing: Form; Date or File No.	Exhibit No.
Mar. 14, 1941	10, 1946	B-2
May 14, 1941	10, 1946	B-3
Apr. 28, 1942	10, 1946	B-4
Apr. 14, 1943	10, 1946	B-5
Apr. 27, 1944	10, 1946	B-6
Apr. 18, 1945	10, 1946	B-7
Apr. 23, 1946	10-K, 1946	B-8
Apr. 9, 1947	10-K, 1946	B-9
June 1, 1947	S-1, (2-7075)	7(b)
Apr. 1, 1948	S-1, (2-7671)	7(b)(1)
May 20, 1948	S-1, (2-7671)	7(b)(2)
Oct. 1, 1948	10-K, 1948	4
Apr. 20, 1949	10-K, 1949	1
Apr. 24, 1950	8-K, Apr. 1950	1
Apr. 18, 1951	8-K, Apr. 1951	1
Oct. 1, 1951	8-K, Nov. 1951	1
Apr. 21, 1952	8-K, Apr. 1952	1
Dec. 1, 1952	S-9, (2-11120)	2(b)(9)
Apr. 15, 1953	8-K, Apr. 1953	2
Apr. 19, 1954	8-K, Apr. 1954	1
Oct. 1, 1954	8-K, Oct. 1954	1
Apr. 18, 1955	8-K, Apr. 1955	1
Apr. 24, 1956	10-K, 1956	1
May 1, 1957	S-9, (2-13260)	2(b)(15)
Apr. 10, 1958	8-K, Apr. 1958	1
May 1, 1959	8-K, May 1959	2
Apr. 18, 1960	8-K, Apr. 1960	1
Apr. 19, 1961	8-K, Apr. 1961	1
Oct. 1, 1961	8-K, Oct. 1961	2
Mar. 1, 1962	8-K, Mar. 1962	3(a)
June 1, 1964	8-K, June 1964	1
May 1, 1966	8-K, May 1966	2
July 1, 1967	8-K, July 1967	2
July 1, 1968	8-K, July 1968	2
Apr. 25, 1969	8-K, Apr. 1969	1
Apr. 21, 1970	8-K, Apr. 1970	1

Sept. 1, 1970	8-K, Sept. 1970	2
Feb. 1, 1971	8-K, Feb. 1971	2
Aug. 1, 1972	8-K, Aug. 1972	2
June 1, 1973	8-K, June 1973	1
Mar. 1, 1974	8-K, Apr. 1974	2
Dec. 1, 1974	8-K, Dec. 1974	1
Oct. 1, 1975	S-7, (2-60082)	2(b)(3)
Apr. 28, 1976	S-7, (2-60082)	2(b)(4)
Apr. 28, 1977	S-7, (2-60082)	2(b)(5)
Nov. 1, 1977	S-7, (2-62415)	2(b)(3)
Apr. 28, 1978	S-7, (2-62415)	2(b)(4)
Oct. 1, 1978	10-K, 1978	D(1)
Oct. 1, 1979	S-7, (2-66484)	2(b)(3)
Mar. 1, 1980	10-K, 1980	4(c)
Apr. 28, 1981	S-16, (2-74923)	4(c)
Nov. 1, 1981	S-16, (2-74923)	4(d)
Dec. 1, 1981	10-K, 1981	4(c)
Apr. 29, 1982	10-K, 1982	4(c)
May 1, 1983	10-K, 1983	4(c)
Apr. 30, 1984	S-3, (2-95814)	4(c)
Mar. 1, 1985	10-K, 1985	4(c)
Nov. 1, 1986	10-K, 1986	4(c)
May 1, 1987	10-K, 1987	4(c)
July 1, 1990	S-3, (33-37431)	4(c)
Dec. 1, 1990	10-K, 1990	4(c)
Mar. 1, 1992	10-K, 1992	4(d)
Apr. 1, 1993	10-Q, June 30, 1993	4(a)
June 1, 1993	10-Q, June 30, 1993	4(b)
Nov. 1, 1993	S-3, (33-51167)	4(a)(3)
Jan. 1, 1994	10-K, 1993	4(a)(3)
Sept. 2, 1994	8-K, Sept. 1994	4(a)
May 1, 1996	10Q, June 30, 1996	4(a)
Nov. 1, 1996	10-K, 1996	4(a)(3)
Feb. 1, 1997	10-Q, Mar. 31, 1997	4(a)
April 1, 1998	10-Q, Mar. 31, 1998	4(a)

			4.03*		Indenture, dated as of Oct. 1, 1993, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 — Exhibit 4(a)).
			4.04*		Indentures supplemental to Indenture dated as of Oct. 1, 1993:

Dated as of	Previous Filing: Form; Date or File No.	Exhibit No.
Nov. 1, 1993	S-3, (33-51167)	4(b)(2)
Jan. 1, 1994	10-K, 1993	4(b)(3)
Sept. 2, 1994	8-K, Sept. 1994	4(b)
May 1, 1996	10-Q, June 30, 1996	4(b)
Nov. 1, 1996	10-K, 1996	4(b)(3)
Feb. 1, 1997	10-Q, Mar. 31, 1997	4(b)
April 1, 1998	10-Q, Mar. 31, 1998	4(b)

120

	4.05*	Indenture date May 1, 1998, between PSCo and The Bank of New York, providing for the issuance of Subordinated Debt Securities (Form 8-K, May 6, 1998 — Exhibit 4.2).
	4.06*	Supplemental Indenture dated May 11, 1998, between PSCo and The Bank of New York, (Form 8-K, May 6, 1998 — Exhibit 4.3).
	4.07*	Preferred Securities Guarantee Agreement dated May 11, 1998, between PSCo and The Bank of New York, (Form 8-K, May 6, 1998 — Exhibit 4.4).
	4.08*	Amended and Restated Declaration of Trust of PSCo Capital and Trust I date May 11, 1998, (Form 8-K, May 6, 1998 — Exhibit 4.1).
	4.09*	Indenture dated July 1, 1999, between PSCo and The Bank of New York, providing for the issuance of Senior Debt Securities (Form 8-K, July 13, 1999, Exhibit 4.1) and Supplemental Indenture dated July 15, 1999, between PSCo and The Bank of New York (Form 8-K, July 13, 1999, Exhibit 4.2).
	10.01*	Amended and Restated Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between the Registrant and Amax Inc. on behalf of its division, Amax Coal Company (Form 10-K, Dec. 31, 1984 — Exhibit 10(c)(1) ).
	10.02*	First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective Jan. 1, 1988 between the Registrant and Amax Coal Company (Form 10-K, Dec. 31, 1988-Exhibit 10(c)(2).
	10.03*	Supplemental Executive Retirement Plan for Key Management Employees, as amended and restated March 26, 1991 (Form 10-K, Dec. 31, 1991 — Exhibit 10(e)(2)).
	10.04*	Executive Savings Plan (Form 10-K, Dec. 31, 1991 — Exhibit 10(e)(5)).
	10.05*	Form of Key Executive Severance Agreement, as amended on Aug. 22, and Nov. 27, 1995. (Form 10-K, Dec. 31, 1995 — Exhibit 10(3)(4)).
	12.01	Statement of Computation of Ratio of Earnings to Fixed Charges
	23.01	Consent of Independent Accountants
	99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995
(b) Reports on Form 8-K — The following report on Form 8-K was filed either during the three months ended Dec. 31, 2000, or between Dec. 31, 2000 and the date of this report. None

121

SPS

(a)	1.		Financial Statements and Schedules		Page
			Included in Part II of this report:
			Report of Independent Accountants for the years ended Dec. 31, 2000, 1999, and 1998.		xx
			Statements of Income for the three years ended Dec. 31, 2000.		xx
			Statements of Cash Flows for the three years ended Dec. 31, 2000.		xx
			Balance Sheets, Dec. 31, 2000 and 1999.		xx
			Notes to Financial Statements.		xx

Exhibits

*: indicates incorporation by reference

			2.01*		Agreement and Plan of Reorganization dated Aug. 22, 1995 (Form 8-K, Exhibit 2, dated Aug. 22, 1995).
			3.01*		Amended and Restated Articles of Incorporation dated Sept. 30, 1997 (Form 10-K, Dec. 31, 1997, Exhibit 3(a)(2)).
			3.02*		By-laws dated Sept. 29, 1997 (Form 10-K, Dec. 31, 1997, Exhibit 3(b)(2)).
			4.01*		Indenture, dated as of Aug. 1, 1946, providing for the issuance of First Mortgage Bonds (Registration No. 2-6910, Exhibit 7-A).
			4.02*		Indentures supplemental to Indenture dated as of Aug. 1, 1946:

Dated as of	Previous Filing: Form; Date or File No.	Exhibit No.
Feb. 1, 1967	2-25983	2-S
Oct. 1, 1970	2-38566	2-T
Feb. 9, 1977	2-58209	2-Y
March 1, 1979	2-64022	b(28)
April 1, 1983 (two)	10-Q, May 1983	4(a)
Feb. 1, 1985	10-K, Aug. 1985	4(c)
July 15, 1992 (two)	10-K, Aug. 1992	4(a)
Dec. 1, 1992 (two)	10-Q, Feb. 1993	4
Feb. 15, 1995	10-Q, May 1995	4
March 1, 1996	333-05199	4(c)

			4.03*		Indenture dated Feb. 1, 1999 between SPS and The Chase Manhattan Bank (Form 8-K, Feb. 25, 1999, Exhibit B).
			4.04*		Supplemental Indenture dated March 1, 1999, between SPS and The Chase Manhattan Bank (Form 8-K, Feb. 25, 1999, Exhibit C).
			4.05*		Red River Authority for Texas Indenture of Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 — Exhibit 4(b)).

122

	4.06*	Indenture dated Oct. 21, 1996, between SPS and Wilmington Trust Company, (Form 10-Q, Nov. 30, 1996 — Exhibit 4(a)).
	4.07*	Supplemental Indenture dated Oct. 21, 1996, between SPS and Wilmington Trust Company, (Form 10-Q, Nov. 30, 1996 — Exhibit 4(b)).
	4.08*	Guarantee Agreement dated Oct. 21, 1996, between SPS and Wilmington Trust Company, (Form 10-Q, Nov. 30, 1996 — Exhibit 4(c)).
	4.09*	Amended and Restated Trust Agreement dated Oct. 21, 1996, among SPS, David M. Wilks, as initial depositor, Wilmington Trust Company and the administrative trustees named therein (Form 10- Q, Nov. 30, 1996 — Exhibit 4(d)).
	4.10*	Agreement as to Expenses dated Oct. 21, 1996, between SPS and Southwestern Public Service Capital I, (Form 10-K, Dec. 31, 1996 — Exhibit F).
	10.01*	Coal Supply Agreement (Harrington Station) between SPS and TUCO, dated May 1, 1979 (Form 8-K, May 14, 1979 — Exhibit 3).
	10.02*	Master Coal Service Agreement between Swindell-Dressler Energy Supply Company and TUCO, dated July 1, 1978 (Form 8-K, May 14, 1979 — Exhibit 5(A)).
	10.03*	Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Company and TUCO (Form 8-K, May 14, 1979 — Exhibit 5(B)).
	10.04*	Coal Supply Agreement (Tolk Station) between SPS and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, Feb. 28, 1982 — Exhibit 10(b)).
	10.05*	Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, Feb. 28, 1982 — Exhibit 10(c)).
	10.06*	Incentive Compensation Plan (an Executive Management Plan) as amended July 23, 1996 (Form 10-K, Aug. 31, 1996 — Exhibit 10(a)).
	10.07*	1989 Stock Incentive Plan as amended April 23, 1996 (Form 10-K, Aug. 31, 1996 — Exhibit 10(b)).
	10.08*	Director's Deferred Compensation Plan as amended Jan. 10, 1990 (Form 10-K, Aug. 31, 1996 — Exhibit 10(c)).
	10.09*	Supplemental Retirement Income Plan as amended July 23, 1991 (Form 10-K, Aug. 31, 1996 — Exhibit 10(e)).
	10.10*	EPS Performance Unit Plan dated Oct. 27, 1992 (Form 10-K, Aug. 31, 1996 — Exhibit 10(a)).
	12.01	Statement of Computation of Ratio of Earnings to Fixed Charges
	23.01	Consent of Independent Accountants
	99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995
(b) Reports on Form 8-K — The following report on Form 8-K was filed either during the three months ended Dec. 31, 2000, or between Dec. 31, 2000 and the date of this report. None

123

SCHEDULE II

UTILITY SUBSIDIARIES OF
XCEL ENERGY INC.

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Years Ended December 31, 2000, 1999 and 1998

					Additions
			Balance at beginning of period		Charged to income			Charged to other accounts			Deductions from reserves(1)		Balance at end of year
			(in thousands)
Reserve deducted from related assets:
	Provision for uncollectible accounts:
		2000	$	5,503	$	5,642		$	3,929		$	10,122	$	4,952

		1999	$	3,949	$	8,546		$	4,550		$	11,542	$	5,503

		1998	$	7,256	$	8,580		$	4,419		$	16,306	$	3,949

NSP-Wisconsin
Reserve deducted from related assets:
	Provision for uncollectible accounts:
		2000	$	943	$	2,269		$	1,006		$	3,420	$	798

		1999	$	825	$	1,200		$	806		$	1,888	$	943

		1998	$	656	$	1,514		$	722		$	2,067	$	825

PSCo
Reserve deducted from related assets:
	Provision for uncollectible accounts:
		2000	$	2,533	$	15,011		$	37		$	6,229	$	11,352

		1999	$	2,254	$	6,225		$	2		$	5,948	$	2,533

		1998	$	2,272	$	5,593		$	(32	)	$	5,579	$	2,254

SPS
Reserve deducted from related assets:
	Provision for uncollectible accounts:
		2000	$	682	$	1,475		$	0		$	1,312	$	845

		1999	$	1,695	$	(160	)	$	(2	)	$	851	$	682

		1998	$	2,442	$	400		$	(7	)	$	1,140	$	1,695

(1): Uncollectible accounts written off or transferred to other parties.

124

NSP-Minnesota Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

	NSP-MINNESOTA
March 23, 2000	/s/ EDWARD J. MCINTYRE Edward J. McIntyre Vice President and Chief Financial Officer (Principal Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

/s/ WAYNE H. BRUNETTI Wayne H. Brunetti President, Chief Executive Officer and Chairman (Principal Executive Officer)		/s/ EDWARD J. MCINTYRE Edward J. McIntyre Director
/s/ DAVID E. RIPKA David E. Ripka Vice President and Controller (Principal Accounting Officer)		/s/ RICHARD C. KELLY Richard C. Kelly Director

125

NSP-Wisconsin Signatures

	NSP-WISCONSIN
March 23, 2000	/s/ EDWARD J. MCINTYRE Edward J. McIntyre Vice President and Chief Financial Officer (Principal Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

/s/ JEROME L. LARSEN Jerome L. Larsen President and Chief Executive Officer (Principal Executive Officer)		/s/ WAYNE H. BRUNETTI Wayne H. Brunetti Chairman
/s/ DAVID E. RIPKA David E. Ripka Vice President and Controller (Principal Accounting Officer)		/s/ EDWARD J. MCINTYRE Edward J. McIntyre Director
/s/ RICHARD C. KELLY Richard C. Kelly Director

126

PSCo Signatures

	PUBLIC SERVICE COMPANY OF COLORADO
March 23, 2000	/s/ EDWARD J. MCINTYRE Edward J. McIntyre Vice President and Chief Financial Officer (Principal Finance Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

/s/ WAYNE H. BRUNETTI Wayne H. Brunetti President, Chief Executive Officer and Chairman (Principal Executive Officer)		/s/ EDWARD J. MCINTYRE Edward J. McIntyre Director
/s/ DAVID E. RIPKA David E. Ripka Vice President and Controller (Principal Accounting Officer)		/s/ RICHARD C. KELLY Richard C. Kelly Director

127

SPS Signatures

	SOUTHWESTERN PUBLIC SERVICE CO.
March 23, 2000	/s/ GARY L. GIBSON Gary L. Gibson President and Chairman (Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

/s/ GARY L. GIBSON

Gary L. Gibson
Director

/s/ DAVID HUDSON

David Hudson
Secretary and Treasurer
(Principal Financial and Accounting Officer)

128