Registrant's telephone number, including area code: 612-330-5500

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

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

Common Stock, $0.01 Par Value
(Title of Class)

REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL
INSTRUCTION I (1)(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS
FORM WITH THE REDUCED DISCLOSURE FORMAT.

Item 1.—Business

    Northern States Power Company (formerly Northern Power Corporation and hereinafter NSP-Minnesota) was incorporated in 2000 under the laws of Minnesota. Its executive offices are located at 414 Nicollet Mall, Minneapolis, Minnesota 55401 (Phone 612-330-5500). NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc., a Minnesota corporation (formerly named Northern States Power Company and hereinafter Xcel Energy). On August 18, 2000, New Century Energies, Inc., a Delaware company (NCE), merged with and into the former Northern States Power Company, a Minnesota corporation, (Former NSP). Immediately following the merger, the surviving entity changed its name to Xcel Energy Inc. Xcel Energy became a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Effective with the merger, Xcel Energy assigned all assets, liabilities and operations relating to Former NSP's electric and natural gas utility operations to NSP-Minnesota, along with the following subsidiaries: United Power and Land Co., First Midwest Auto Park, NSP Nuclear Corp., Nuclear Management Co. LLC and NSP Financing I. Former NSP owned other subsidiaries that remained with Xcel Energy. Former NSP provided corporate and other administrative services to its subsidiaries and allocated or charged to its subsidiaries, as appropriate, a portion of these corporate and administrative service charges. The remaining costs related to these services remained at Former NSP. With the merger, the corporate and administrative service charges for all Xcel Energy-owned entities, including Former NSP, were transferred to Xcel Energy Services Company (Xcel Services), a wholly-owned subsidiary of Xcel Energy. Xcel Services will allocate its costs back to all Xcel Energy-owned entities, including NSP-Minnesota.

    NSP-Minnesota is a public utility engaged in the generation, transmission and distribution of electricity and the transportation, storage and distribution of natural gas. NSP-Minnesota serves retail customers in Minnesota, North Dakota and South Dakota. NSP-Minnesota provides generation, transmission and distribution of electricity throughout a 30,000 square mile service area 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 approximately 120 communities in Minnesota, North Dakota and South Dakota. Of the more than 2.8 million people served by NSP-Minnesota, the majority are in the Minneapolis-St. Paul metropolitan area. In 1999, more than 73 percent of the electric retail revenue of NSP-Minnesota was derived from sales in the Minneapolis-St. Paul metropolitan area, and more than 68 percent of its retail gas revenue was derived from sales in the St. Paul metropolitan area. NSP-Minnesota provides retail electric utility service to approximately 1.3 million customers and gas utility service to approximately 0.4 million customers.

    Regulated electric and gas utility companies face several challenges, including: increasing competition, increasing pressure to control costs, uncertainties in regulatory processes and increasing costs of compliance with environmental laws and regulations. In addition, there are uncertainties related to permanent disposal of spent nuclear fuel. For further discussion of these matters, see Management's Discussion and Analysis under Item 2 and Notes to Financial Statements under Item 13.

    Except for historical information, the matters discussed in this registration statement are forward-looking statements that are subject to certain risks, uncertainties and assumptions, as discussed in Management's Discussion and Analysis under Item 2 and Exhibit 99.02 to this registration statement.

THE MERGER

    As discussed above, on August 18, 2000, NSP and NCE completed the merger. Prior to completion of the merger, NSP-Minnesota was Northern Power Corporation and had no operations. The operations and financial results discussed herein represent the results of the utility operations of the Former NSP and the subsidiaries transferred from Xcel Energy as described previously. Comparisons to the prior year in Management's Discussion and Analysis represent a comparison of results of operations of NSP-Minnesota as if the merger was completed as of January 1 of the earliest period presented.

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UTILITY REGULATION AND REVENUES

General

    Retail sales 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, property transfers within the state of Minnesota when the asset value is in excess of $100,000, 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. 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 Federal Energy Regulatory Commission (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 NSP-Minnesota. Federal, state and local agencies also have jurisdiction over many of NSP-Minnesota's other activities.

    The Minnesota Environmental Quality Board (MEQB) is empowered to select and designate sites for new power plants with a capacity of 50 megawatts (Mw) or more and wind energy conversion plants with a capacity of 5 Mw or more. It also designates routes for electric transmission lines with a capacity of 200 kilovolts (kv) or more. The MEQB also evaluates such sites and routes for environmental compatibility. The MEQB may designate sites or routes different than those proposed by power suppliers. No power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MEQB.

    NSP-Minnesota's utility rates are approved by the FERC and state regulatory commissions in Minnesota, North Dakota and South Dakota. Rates are designed to recover plant investment, operating costs and an allowed return on investment. NSP-Minnesota requests changes in rates for utility services through filings with the governing commissions. Because comprehensive rate changes are requested infrequently in Minnesota, NSP-Minnesota's primary jurisdiction, changes in operating costs can affect NSP-Minnesota's financial results. NSP-Minnesota's retail rate schedules provide for cost-of-energy and resource adjustments to billings and revenues for changes in the cost of fuel for electric generation, purchased energy, purchased gas and, in Minnesota, conservation and energy management program costs. In Minnesota, changes in electric capacity costs are not recovered through the fuel clause. In addition to changes in operating costs, other factors affecting rate filings are sales growth, conservation and demand-side management efforts and the cost of capital.

    Regulated public utilities are allowed to record as assets certain costs that would be expensed by nonregulated enterprises and to record as liabilities certain gains that would be recognized as income by nonregulated enterprises. If restructuring or other changes in the regulatory environment occur, NSP-Minnesota may no longer be eligible to apply this accounting treatment and may be required to eliminate such regulatory assets and liabilities from its balance sheet. Such changes could have a material adverse effect on NSP-Minnesota's results of operations in the period the write-off is recorded. At Dec. 31, 1999, NSP-Minnesota reported on its balance sheet regulatory assets of approximately $103 million and regulatory liabilities of approximately $195 million that would need to be recognized in the income statement in the absence of regulation. In addition to a potential write-off of regulatory assets and liabilities, deregulation and competition may require recognition of certain "stranded costs" not recoverable under market pricing. NSP-Minnesota currently does not expect to write off any "stranded costs" unless market price levels change, or cost levels increase above market price levels. See Note 1 and 10 to the Financial Statements for further discussion of regulatory deferrals.

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    NSP-Minnesota is unable to predict the impact on its operating results from the future regulatory activities of any of the above agencies. NSP-Minnesota strives to comply with all rules and regulations issued by the various agencies.

Revenues

    NSP-Minnesota's financial results depend, in part, on its ability to obtain adequate and timely rate relief from the various regulatory bodies and its ability to control costs. NSP-Minnesota's 1999 utility operating revenues, excluding non-firm electric sales to other utilities of $144 million and miscellaneous electric and gas revenues of $274 million, were subject to regulatory jurisdiction as follows:

*

Settlement proceeding, based upon revenue levels granted with no specified return.

**

Reflects return on equity underlying various rate settlements.

    General rate increases (other than fuel and resource adjustment rate changes) requested and granted in the last five years were as follows (represent annual amounts effective in those years)

Ratemaking Principles in Minnesota

    The MPUC accepts the use of a forecast test year that corresponds to the period when rates are put into effect and allows collection of interim rates subject to refund. The use of a forecast test year and interim rates minimizes regulatory lag.

    The MPUC must order interim rates within 60 days of a rate case filing. Minnesota statutes allow interim rates to be set using (1) updated expense and rate base items similar to those previously allowed, and (2) a return on common equity equal to that granted in the last MPUC order for the utility. The MPUC must make a determination on the application within 10 months after filing. If the final determination does not permit the full amount of the interim rates, the utility must refund the excess revenue collected, with interest. To the extent final rates exceed interim rates, the final rates become effective at the time of the order and retroactive recovery of the difference is not permitted.

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    Minnesota law allows Construction Work in Progress (CWIP) in a utility's rate base. The MPUC has generally included Allowance for Funds Used During Construction (AFC) in revenue requirements for rate proceedings.

Fuel and Purchased Gas Adjustment Clauses

    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 the fuel clause, although changes in capacity charges are not recovered through the fuel clause. NSP-Minnesota's wholesale electric sales customers do not have a fuel clause provision in their contracts. Instead of fuel clause recovery, the contracts provide a fixed rate with 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.

Resource Adjustment Clauses

    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.

Regulatory Matters by Jurisdiction

    Minnesota Commission.   During 1999, NSP-Minnesota recorded charges to earnings of the Minnesota utility's operations of $35 million (before tax), due to the disallowance of rate recovery for accrued 1998 conservation program incentives. In addition, due to the uncertainty of future conservation incentive recovery, NSP-Minnesota did not accrue any conservation incentives for 1999 activity. See Management's Discussion and Analysis under Item 2 for discussion of this issue.

    On July 27, 1999, the MPUC issued an order requiring an investigation into the reasonableness of NSP-Minnesota's retail electric rates in Minnesota. As required by the rate investigation order, NSP-Minnesota filed detailed schedules and an explanation of why it believes its current rates continue to be just and reasonable. In January 2000, the MPUC accepted NSP-Minnesota's filing, closed the investigation and transferred any further analysis to the NSP-NCE merger proceeding.

    In December 1999, NSP-Minnesota signed separate agreements with the Minnesota Office of Attorney General and the Minnesota Energy Consumers related to stipulated terms under which those parties would support NSP's merger with NCE. Under the agreements, which contained substantially the same financial terms, NSP-Minnesota agreed to reduce its Minnesota electric rates by $10 million per year, or approximately 0.6 percent less than current levels, for 2001-2005. Under the agreements, NSP-Minnesota's electric rates may not otherwise be increased through 2005, except under limited circumstances.

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    In January 2000, NSP-Minnesota also signed a separate agreement with the Minnesota Dept. of Commerce (MDC), in which the MDC would support NSP's merger with NCE. Under the agreement NSP-Minnesota agreed not to seek recovery of certain merger cost from customers, to meet various quality standards and to certain provisions affecting the regulatory oversight of Xcel Energy.

    During 1999, NSP-Minnesota obtained approval from the MPUC to include the cost of electricity futures and options in the fuel clause. This approval allows NSP-Minnesota to recover the cost of hedging against price volatility in electricity markets.

    With the exception of any filings regarding conservation program incentives, no filings requesting a general electric or gas rate increase are anticipated in Minnesota in 2000.

    North Dakota Commission.   In July 1998, the NDPSC ordered its staff to conduct an investigation of NSP-Minnesota's North Dakota jurisdictional electric earnings. The purpose of the investigation was to determine if existing rates were fair and reasonable given earnings results. In December 1999, North Dakota Commission Staff issued an investigation report finding NSP-Minnesota to be in an excess revenue position of about $0.8 million. In January 2000, NSP-Minnesota entered into a settlement agreement with North Dakota Commission staff. The settlement calls for a $250,000 electric rate reduction, closing of the earnings investigation case, the North Dakota Commission approval of Xcel Energy's application to merge with NCE and the filing of a performance-based regulation plan.

    In December 1999, the NDPSC approved NSP-Minnesota's petition for a gas rate correction, increasing annual gas revenue by approximately $300,000.

    South Dakota Commission.   In 1999, the SDPUC approved NSP-Minnesota's request for an order establishing NSP-Minnesota as a regulated intrastate gas pipeline in South Dakota, including a request for approval of initial large volume retail intrastate gas transportation rates. NSP-Minnesota had not previously provided natural gas service in South Dakota.

    No general rate filings are anticipated in South Dakota in 2000.

    Federal Energy Regulatory Commission.   In 1996, the FERC issued Orders No. 888 and 889, which have had a significant impact on wholesale electric markets by giving competitors the ability to transmit electricity through utilities' transmission systems.

    In the first quarter of 1998, NSP-Minnesota filed wholesale electric point-to-point and network integration transmission service (NTS) rate cases with the FERC. In March 1999, NSP-Minnesota filed an offer of settlement, which would resolve virtually all issues in the two cases. The offer of settlement provided an approximate 2 percent reduction in point-to-point rates, which combined with anticipated reductions in non-firm discounting is expected to have little or no impact on annual revenue. In addition, the settlement called for an annual increase of approximately $1 million in ancillary service revenues. Finally, the settlement placed a cap on NSP-Minnesota's annual NTS payment liabilities to its five NTS customers at $10 million per year. The point-to-point and ancillary rates would be effective October 1998. The offer also included a three-year moratorium period on future transmission rate changes. In December 1999, the FERC issued an order approving the settlement.

    In June 1998, the FERC issued an order in the electric transmission rate case requiring NSP-Minnesota to interrupt service to its own retail customers proportionally with curtailment of wholesale transmission-only customers taking service under NSP-Minnesota's Order No. 888 transmission tariff. When NSP-Minnesota's transmission lines are constrained or about to become overloaded, the FERC order would have required NSP-Minnesota to interrupt service to retail customers to reduce transmission loadings on constrained facilities on a pro rata basis with curtailment of wholesale transactions. In August 1998, NSP-Minnesota filed an appeal of the FERC orders with the U.S. Court of Appeals, Eighth Circuit. In May 1999, the Eighth Circuit reversed and remanded the FERC ruling. In November 1999, the FERC issued an order on remand providing an acceptable

6

resolution to the matter and NSP-Minnesota submitted a compliance filing, which the FERC accepted in December 1999. However, in November 1999, Enron Power Marketing, Inc. requested U.S. Supreme Court review of the Eighth Circuit ruling. In February 2000, the Supreme Court denied review and the appeal is now complete.

ELECTRIC UTILITY OPERATIONS

Competition and Industry Restructuring

    NSP-Minnesota's electric sales are subject to competition in some areas from municipally owned systems, cooperatives, other utilities and independent power producers. Electric service also increasingly competes with other forms of energy. Although NSP-Minnesota cannot predict the extent to which its future business may be affected by competition, NSP-Minnesota believes it will be in a position to compete effectively.

    In addition to competition for sales, the electric utility industry is undergoing a possibly significant restructuring. Depending on future regulatory decisions, utilities like NSP-Minnesota may be required to separate the functions of power generation, transmission, distribution and energy services. NSP-Minnesota cannot predict the ultimate result of restructuring. However, we are taking proactive steps to effectively compete in a restructured energy marketplace, such as joining the Midwest Independent System Operator (MISO) and forming a Nuclear Management Company with other utilities.

    Wholesale Competition.   The Energy Policy Act of 1992 (Energy Act) is designed to promote competition in the development of wholesale power generation in the electric industry, and, since its enactment, has been a catalyst for comprehensive and significant changes in the operation of electric utilities, including increased competition. The Act's reform of PUHCA promoted creation of wholesale nonutility power generators and authorized the FERC to require utilities to provide wholesale transmission services to third parties. The legislation allows utilities and nonregulated companies to build, own and operate power plants nationally and internationally without being subject to restrictions that previously applied to utilities under the PUHCA.

    In 1996, the FERC issued Orders No. 888 and 889 to foster competition in the electric utility industry. These orders give competing wholesale suppliers the ability to transmit electricity through a utility's transmission system. Order No. 888 grants nondiscriminatory access to transmission service. Order No. 889 seeks to ensure a fair market by imposing standards of conduct on transmission system owners, by requiring separation of the wholesale power supply function from the transmission system operation function, and by mandating the posting of transmission availability and pricing information on an electronic bulletin board. NSP-Minnesota has made open access transmission tariff filings and compliance filings with the FERC and believes it is taking the proper steps to comply with these rules.

    In compliance with FERC Orders No. 888 and 889, NSP-Minnesota has separated personnel who perform the merchant function, which includes power and energy marketing, from personnel who perform the transmission system operation function. NSP-Minnesota's merchant function, Energy Marketing, performs power and energy marketing (both sales and purchases). The sales and revenue provided by this function is classified as sales for resale. Because of Orders No. 888 and 889, NSP Energy Marketing must pay the same rates as other utilities for use of NSP-Minnesota's transmission system.

    In 1998, NSP-Minnesota expanded its wholesale energy marketing efforts by formally establishing an Energy Marketing division. Energy Marketing is responsible for meeting the requirements of NSP-Minnesota's retail and wholesale electric customers for low-cost energy while optimizing earnings from NSP-Minnesota's generation resources. Energy Marketing is no longer competing with only regional utilities when it buys and sells excess power to wholesale customers, but with power marketers from all over the United States. As more participants join the market, margins are expected to decline.

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Energy Marketing is developing its wholesale power marketing capabilities to compete on a national basis.

    Although NSP-Minnesota has contracts with several municipal customers, a competitive market requires NSP-Minnesota to remain competitive in the entire wholesale market because many parties, including power marketers, are now able to use NSP-Minnesota's transmission lines to transport electricity. Rate discounts and negotiated rates are being offered to current and potential municipal power supply customers. In the past several years, these customers have been evaluating a variety of energy sources to provide their electric supply. The process of making a wholesale energy sale is now much more competitive and can be contingent upon the availability of transmission service.

    In December 1999, FERC issued order No. 2000, which adopted new rules that encourage all wholesale transmission service providers to join regional transmission organizations (RTOs).

    Retail Competition.   Some states have begun to allow retail customers to choose their electricity suppliers, and many other states are considering proposals to increase competition in the supply of electricity. Electric industry restructuring has not yet emerged as a major issue in Minnesota. In 1998, the Minnesota Legislature directed the Legislative Electric Energy Task Force (LEETF) to study restructuring. The LEETF solicited comments from NSP-Minnesota and other interested parties on four topics: bulk power systems; distribution reliability, safety and maintenance; energy prices and price protection mechanisms; and universal service. Based on those comments, the LEETF filed a report with the Minnesota Legislature in January 1999, concluding that additional study was necessary. The Minnesota Legislature did not act on electric restructuring in 1999. The LEETF is considering introducing a major bill to focus the discussion in 2000. The Minnesota Department of Commerce (MDC) has announced it intends to prepare a comprehensive electric restructuring bill for introduction in 2001. The MDC and the Minnesota Chamber of Commerce may be seeking passage of a "consumer information" bill in 2000, requiring the unbundling of rates on consumers' bills. However, the Minnesota Legislature is not expected to take significant action on this matter until the 2001 session.

    In 1997, the NDPSC adopted the National Association of Regulatory Utility Commissioners' Principles to Guide the Restructuring of the Electric Industries, which suggest that industry changes should only occur when they result in economic efficiency and serve the broader public interest. Specific principles address protecting reliability, providing customers with meaningful choice, sharing benefits and stranded costs between ratepayers and shareholders, protecting the environment and reaffirming state commission responsibility for determining restructuring policies. The NDPSC has taken no further action on restructuring.

    In 1997, the North Dakota Legislature established an Electric Utility Committee (EUC) of six legislators charged with studying the impact of competition on the electric industry. By statute, the committee has six years to study the impact of competition on the electric energy industry in the state. The EUC is formulating tax law changes intended to remove disparities between investor-owned and cooperative systems in the state. In 2000, the EUC will begin assessing the need for modifications to the Territorial Integrity Act, a law governing distribution service territories within the state. Based on its findings, the EUC intends on introducing tax or service territory legislation, if necessary, to the 2001 Legislature.

    NSP-Minnesota has proposed to fill future needs for new generation through competitive bid solicitations. The use of competitive bidding to select future generation sources allows NSP-Minnesota to take advantage of the developing competition in this sector of the industry. NSP-Minnesota's proposal, which has been approved by the MPUC, allows NRG Energy, Inc., one of Xcel Energy Inc.'s nonregulated subsidiaries and NSP-Minnesota's generation business unit to bid in response to company solicitations for proposals.

    NSP-Minnesota plans to continue to be a low-cost supplier of electricity and an active participant in the more competitive market for electricity expected in the future. NSP-Minnesota will continue to

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work with regulators to develop a tariff and infrastructure that will support a competitive electric environment. NSP-Minnesota is positioning itself for the competitive environment by offering value-added services tied to our core businesses. The timing of regulatory and legislative actions regarding restructuring and their impact on NSP-Minnesota cannot be predicted at this time and may be significant.

Transmission Operations

    During 1999, NSP-Minnesota joined the Midwest ISO, a FERC approved Regional Transmission Organization (RTO). This action commits the NSP transmission system to control by the Midwest ISO and ensures transmission operations in compliance with FERC Order No. 888 .

    The Midwest ISO intends to commence operations in 2001. The Midwest ISO will administer transmission service for most of the area extending east from NSP-Minnesota's service area to Pennsylvania and south through Illinois and Kentucky. NSP-Minnesota remains a member of the Mid-Continent Area Power Pool (MAPP). MAPP recently signed an agreement with the Midwest ISO, which may further broaden the scope of the Midwest ISO and regional markets for transmission service.

Nuclear Management Company (NMC)

    Recent development regarding NSP-Minnesota's expressed intention to form an independent nuclear management company include:

•

During 1999, NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin Public Service Corp. and Alliant Energy established an NMC to improve plant performance and reliability, strengthen operational efficiency, maintain high safety levels and reduce costs. The four companies operate seven nuclear units at five sites, with a total generation capacity exceeding 3,650 megawatts.



•

In late 1999, NMC member utilities filed with the Nuclear Regulatory Commission (NRC) to transfer plant operating licenses to the NMC. The four partners, including NSP-Minnesota, will retain ownership of their respective nuclear plant assets. License transfer would allow the NMC to become an operating company in 2000. During 1999, NSP-Minnesota's board of directors and the boards of the other utilities approved the transfer of the nuclear operating licenses for their respective companies to the NMC. The request to transfer operating licenses requires approval from federal regulators, including the NRC.

Automated Meter Reading

    In 1997, NSP-Minnesota began installing a wireless automated meter reading system that allows us to remotely read customer meters. Approximately 900,000 automated electric and gas meters have been installed. NSP-Minnesota contracted with an affiliate of CellNet Data Systems, Inc., which owns and operates the communication network that provides daily meter readings to NSP-Minnesota for automated electric and gas meters. In February 2000, CellNet announced it was filing a Chapter 11 bankruptcy. During 2000, NSP-Minnesota renegotiated the contracts with the entity that is taking CellNet out of bankruptcy. NSP-Minnesota does not expect CellNet's financial difficulties to pose significant operational risk to NSP-Minnesota's ability to continue to read customer meters or otherwise conduct business.

Capability and Demand

    NSP-Minnesota's electric production and transmission systems are interconnected with the production and transmission system of Northern States Power Company, a Wisconsin corporation, (NSP-Wisconsin) (the NSP integrated system). NSP-Wisconsin primarily relies on plants operated by NSP-Minnesota for base load generation. Historically, approximately 80 percent of the total kilowatt

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hour (kwh) requirements of NSP-Wisconsin were provided by NSP-Minnesota generating facilities or purchases made by NSP-Minnesota for NSP integrated system use.

    NSP-Wisconsin owns fourteen thermal electric generating units on four sites and nineteen hydroelectric plants. These plants are used as "peaking plants"—called into service during periods of high demand for electricity—or as "intermediate load" plants to supplement the output of NSP-Minnesota's base load plants.

    NSP-Wisconsin and NSP-Minnesota share the electric production and transmission costs of the NSP integrated system. The cost-sharing arrangement between the companies is referred to as the Interchange Agreement. It is a FERC-regulated agreement.

    Historically, NSP-Wisconsin's share of the NSP integrated system annual production and transmission costs has been between 15 to 16 percent. Revenues received from billings to NSP-Wisconsin for its share of NSP-Minnesota's production and transmission costs are recorded as electric operating revenues on NSP-Minnesota's income statement. The portions of NSP-Wisconsin's production and transmission costs that were charged to NSP-Minnesota were recorded as purchased and interchange power expenses and other operation and maintenance expenses, respectively, on NSP-Minnesota's income statement. For further information see Note 9 to Financial Statements.

    The 1999 maximum demand for the NSP integrated system of 7,990 Mw occurred on July 29, 1999. Resources available at that time included 7,176 Mw of system-owned capability and 2,024 Mw of purchased capability, net of contracted sales. NSP-Minnesota owned 6,311 Mw of capacity at that time. The NSP integrated system carried a reserve margin for 1999 of 15 percent to avoid the MAPP penalty for reserve shortfalls. As a member of MAPP, the NSP integrated system must own or contract for enough electric generating capacity to serve its own customers plus an additional reserve requirement to protect the system from failure in case of an unexpected generating station outage or demand due to severe weather. The NSP integrated system's reserve requirement is determined jointly with the other parties to the MAPP agreement. The minimum reserve margin requirement for MAPP members is 15 percent.

    Assuming normal weather, the NSP integrated system expects its 2000 summer electric peak demand to be 7,696 Mw. NSP-Minnesota expects to meet its summer peak and the MAPP reserve requirements through a combination of generation and purchases. See Note 13 of Notes to Financial Statements for more discussion of power agreement commitments.

    During 1998, NSP-Minnesota filed an electric resource plan covering the NSP integrated system with the MPUC for the period 1998 to 2012. The plan describes how NSP-Minnesota intends to meet the energy needs of its electric customers and includes an approximate schedule of the timing of resource solicitation to meet such needs. The plan contains conservation programs to reduce our 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 1.7 percent annual growth in our energy and peak demand requirements.



—

Outlines our demand side management and conservation programs.



—

Shows new capacity needs of 140 Mw in 2003 and 2,400 Mw by 2012.



—

Describes the programs for achieving the mandated renewable energy sources of 425 Mw of wind and 125 Mw of biomass.



—

Updates the status of spent nuclear fuel at the Prairie Island plant and describes how it can continue to operate until the year 2007 with the number of casks that have been authorized.

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

—

Continued use of existing generation facilities.



—

Demand reduction of an additional 1,080 Mw by 2012 through conservation and load management.



—

425 Mw of wind energy and 125 Mw of biomass energy under contract by 2002.



—

Acquisition of competitively priced resources through competitive bidding.

    During 1999, the MPUC voted to approve most aspects of the resource plan. However, the MPUC ordered us to acquire an additional 400 Mw of wind generation by 2012, subject to least cost determination.

    Minnesota utilities are required under Minnesota law to use values established by the MPUC, which assign a range of environmental costs to each method of electricity generation when evaluating and selecting generation resource options. These values are known as environmental externalities. The high end of the range of externality values ordered by the MPUC adds about 0.55 cents per kilowatt hour (kwh) to a typical new coal plant and about 0.15 cents per kwh to a natural gas fired plant. The production of carbon dioxide comprises about 60 percent to 80 percent of these amounts.

    NSP-Minnesota continues to implement various demand side management (DSM) programs designed to improve load factor and reduce our power production costs and system peak demands, reducing or delaying the need for additional investment in new generation and transmission facilities. We offer a range of DSM programs, including information programs, rebate and financing programs and rate incentive programs. These programs are designed to increase the value of our service and help our customer base become more energy efficient and competitive. NSP-Minnesota and NSP-Wisconsin's DSM programs have reduced NSP's integrated system peak demand by approximately 1,381 Mw.

    In 1999, we filed with the MPUC our plan to repower two coal-fired units at our Black Dog Plant in Minnesota with natural gas combined-cycle technology. The MPUC and other government agencies will review the merits of the project. Under our proposal, the maximum capacity of Black Dog units 1 and 2 would increase from 175 Mw to 290 Mw. The total cost of the project is estimated to be $156 million. If approved, the repowered units could begin operating in mid-2002.

    NSP-Minnesota has been experiencing increased purchased energy and capacity costs to manage its summer load requirements. Future price spikes that the industry could experience due to weather conditions, outages or other supply and demand considerations could affect our financial results. For more information, see Management's Discussion and Analysis under Item 2.

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    NSP-Minnesota normally maintains between 20 and 40 days of coal inventory at each plant, depending on the plant site. NSP-Minnesota has long-term contracts providing for the delivery of up to 100 percent of its 2000 coal requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather and availability of equipment.

    Based on existing coal contracts, we expect more than 98 percent of the coal we burn in 2000 will have a sulfur content of less than 1 percent. NSP-Minnesota has contracts for a maximum of 27 million tons of low-sulfur coal for the next two years. The contracts are with two Montana coal suppliers (Westmoreland Resources and Big Sky Coal Company) and six Wyoming suppliers (Rochelle Coal Company, Antelope Coal Company, Black Thunder Coal Company, Jacobs Ranch Mine, Belle Ayr Mine and North Rochelle Mine). These arrangements are sufficient to meet 100 percent of the requirements of existing coal-fired plants in 2000 and 2001.

    NSP-Minnesota will purchase approximately 10 percent of our coal requirements in a large active spot market if prices are more favorable than contracted prices.

    Estimated coal requirements at our major coal-fired generating plants and the coal supply for such requirements are:

(1)

Contract expiration dates vary between 2000 and 2005 for western coal. Spot market purchases of other western coal and other fuels will provide the remaining fuel requirements after 2000.

    NSP-Minnesota's current fuel oil inventory is adequate to meet anticipated 2000 requirements. Additional oil may be obtained through spot purchases.

    To operate our nuclear generating plants, we secure 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 2000. These contracts expire at varying times between 2000 and 2005.

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The overlapping nature of contract commitments will allow us to maintain 50 percent to 100 percent coverage beyond 2000. 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 the year 2003 and 30 percent covered through 2010.

    NSP-Minnesota's average electric fuel costs for the past three years are shown below:

*

Includes refuse-derived fuel and wood.

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. See discussion concerning the Nuclear Management Company under "Competition and Industry Restructuring" and in Exhibit 99.01 to this filing.

    In September 1998, NSP-Minnesota received approval from the Nuclear Regulatory Commission (NRC) for an amendment to the Monticello operating license to increase the power level as a result of improvements in technology, equipment and plant performance. This change increased Monticello's summer generating capacity from 545 Mw to 578 Mw.

    NSP-Minnesota previously operated the Pathfinder plant in South Dakota as a nuclear plant from 1964 until 1967. It has since been converted to an oil and gas-fired peaking plant. Most of the plant's nuclear material was removed during 1991. A few millicuries of residual contamination remain at the site. Nuclear power plant operation produces gaseous, liquid and solid radioactive wastes. The discharge and handling of such wastes are controlled by federal regulation. For nuclear power plants, high-level radioactive waste includes used nuclear fuel. Low-level radioactive wastes are produced from other activities at a nuclear plant. They consist principally 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 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 no longer 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 of 1982 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

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fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent storage or disposal facility by 1998. None of NSP's spent nuclear fuel has been accepted by the DOE for disposal. See Item 8—Legal Proceedings and Note 12 to the Financial Statements under for further discussion of this matter.

    NSP-Minnesota, with regulatory and legislative approval, has been providing on-site storage at its Monticello and Prairie Island nuclear plants. In 1979, NSP-Minnesota began expanding the used nuclear fuel storage facilities at its Monticello plant by replacement of the racks in the storage pool. In 1987, NSP-Minnesota completed the shipment of 1,058 used fuel assemblies from the Monticello plant to a General Electric storage facility in Morris, Illinois. 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 prior to a scheduled refueling in June 1995, and adequate space for a subsequent refueling was no longer available. In anticipation of this, NSP-Minnesota, in 1989, proposed construction of a temporary on-site dry cask storage facility for spent nuclear fuel at Prairie Island. In May 1994, the governor of Minnesota signed into law a bill authorizing NSP-Minnesota to install 17 spent fuel casks at Prairie Island. NSP-Minnesota has determined 17 casks will allow facility operation until 2007. As of Dec. 31, 1999, nine storage casks were loaded and stored on the Prairie Island nuclear generating plant site.

    The Minnesota Legislature established several energy resource 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. For more information on the status of these legislative commitments, see Note 13 to the Financial Statements.

    NSP-Minnesota is leading a consortium of private parties to establish a private facility for interim storage of spent nuclear fuel. In 1997, the Private Fuel Storage LLC (PFS) filed a license application with the NRC for a national temporary storage site for spent nuclear fuel. The PFS will undertake the development, licensing, construction and operation of a storage facility on the Skull Valley Indian Reservation in Utah. The NRC review process could take up to three years and will consist of formal evidentiary hearings and opportunity for public input. Storage cask certification efforts are continuing with the two vendors 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 2003. However, due to uncertainty regarding pending regulatory and governmental approvals, it is possible that this interim storage may be delayed or not available at all.

    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. NSP-Minnesota is unable to predict any new requirements or their impact on NSP-Minnesota's facilities and operations.

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

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*

Represents excess (deficiency) of conservation incentives recognized as revenue in comparison to levels billed to retail customers under rates in effect.

**

Customers' accounts for 1996, 1997, 1998 and 1999 may not be fully comparable to prior years due to differences in meter accumulation in a new billing system implemented in 1996.

GAS UTILITY OPERATIONS

Competition/Regulation

    NSP-Minnesota provides retail gas service in the eastern portions of the Twin Cities metropolitan area, northwestern Minnesota, and other regional centers in Minnesota (Faribault, St. Cloud and Winona) as well as portions of eastern North Dakota.

15

    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. NSP-Minnesota provides unbundled transportation service. Transportation service does not have an adverse effect on earnings because our sales and transportation rates have been designed to make us 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. NSP-Minnesota has arranged its gas supply and transportation portfolio to provide flexibility in the event it may be required to terminate its retail merchant sales function.

    NSP-Minnesota has aggressively pursued alternative pricing strategies and service enhancements to provide additional value to customers and to improve its competitive position.

    In 1997, the MPUC approved a negotiated transportation service tariff that provides additional flexibility in discounting gas rates for customers considering a bypass of our system.

    In 1997, the MPUC approved our proposal for a predictable commodity price service rider, which allows firm gas commercial and industrial customers the choice to purchase firm fixed price gas supplies rather than gas supplies whose price changes monthly through the PGA clause.

Business Growth

    NSP-Minnesota's gas utility customer base grew by approximately 23,000 customers during 1999. In December 1999, Former NSP merged with Natrogas Inc., which is based in Minneapolis. The gas utility subsidiary of Natrogas, which had approximately 5,000 gas utility customers, became part of NSP-Minnesota. In addition to exploring new growth opportunities, we are also focusing on conversion of potential customers who are located near our gas mains, but are not connected to the service.

    NSP-Minnesota has a nonutility service that sells service contracts on a variety of home appliances. Working in partnership with local independent service contractors, NSP Advantage Service offers 24-hour appliance repair service to individuals within our service territory.

Capability and Demand

    NSP-Minnesota categorizes its gas supply requirements as firm or interruptible (customers with an alternate energy supply). NSP-Minnesota's maximum daily sendout (firm and interruptible) of 649,094 mmBtu for 1999 occurred on Jan. 4, 1999.

    NSP-Minnesota purchases 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 510,996 mmBtu/day. In addition, NSP-Minnesota has contracted with providers of underground natural gas storage services. Using storage reduces the need for purchases from independent suppliers. These storage agreements provide storage for approximately 17 percent of annual and 24 percent of peak daily, firm requirements of NSP-Minnesota.

    NSP-Minnesota also owns and operates a LNG plant with storage capacity of 2.13 bcf equivalent and three propane-air plants with a storage capacity of 1.4 bcf equivalent to help meet the peak requirements of its firm residential, commercial and industrial customers. These peak-shaving facilities have production capacity equivalent to 224,300 mmBtu of natural gas per day, or approximately 34 percent of peak day firm requirements. NSP's LNG and propane-air plants provide a cost-effective alternative to firm pipeline capacity 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.

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    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 March 1999, the MPUC approved our 1998-99 entitlement levels, which allow us to recover the demand entitlement costs associated with the increase in transportation and storage levels in its monthly PGA. Our filing for approval of our 1999-2000 entitlement levels was approved in March 2000 by the MPUC.

Gas Supply and Costs

    NSP-Minnesota's natural gas supply commitments have been unbundled from our gas transportation and storage commitments. Our gas utility actively seeks 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. Approximately 80 percent of NSP-Minnesota's retail gas customers are served from the Northern pipeline system. NSP-Minnesota has firm gas transportation contracts with the following pipelines, which expire in various years from 2000 through 2013:

    The agreements with Great Lakes, Northern Border, ANR and TransCanada provide for firm transportation service upstream of Northern Natural and Viking, allowing competition among suppliers at supply pooling points and minimizing commodity gas costs.

    In addition to these fixed transportation charge obligations, we have entered into firm gas supply agreements that provide for the payment of monthly or annual reservation charges irrespective of the volume of gas purchased. The total annual obligation is approximately $12 million. These agreements allow us to purchase natural gas at a high load factor at rates below the prevailing market price, reducing the total cost per mmBtu.

    NSP-Minnesota has certain gas supply and transportation agreements that include obligations to purchase and/or deliver specified volumes of gas or to make payments in lieu thereof. At Dec. 31, 1999, NSP-Minnesota was committed to approximately $143 million in such obligations under these contracts, which range from the years 2000-2013. NSP-Minnesota has negotiated "market out" clauses in our new supply agreements, which reduce our purchase obligations if we no longer provide merchant gas service.

    NSP-Minnesota purchases firm gas supply from approximately 19 domestic and Canadian suppliers under contracts with durations of one year to 10 years. We purchase no more than 20 percent of our total daily supply from any single supplier. This diversity of suppliers and contract lengths allows us to maintain competition from suppliers and minimize supply costs. NSP-Minnesota's objective is to be able to terminate its retail merchant sales function, if necessary, to remain competitive in the marketplace or if mandated by regulatory agencies, with minimal cost to our company.

    The following table summarizes the average cost per mmBtu of gas purchased for resale by NSP-Minnesota's regulated retail gas distribution business.

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    The cost of gas supply, transportation service and storage service is recovered through the PGA cost recovery adjustment mechanism.

    Purchases of gas supply or services by NSP-Minnesota from NSP-Wisconsin and Viking Gas Transmission Company (Viking), both subsidiaries of Xcel Energy, are subject to approval by the MPUC. The MPUC has approved all of NSP-Minnesota's transportation contracts with Viking.

*

Customer accounts for 1996, 1997, 1998 and 1999 may not be fully comparable to prior years due to differences in meter accumulation in a new billing system implemented in 1996.

ENVIRONMENTAL MATTERS

    NSP-Minnesota monitors its operations to ensure the environment is not adversely affected and takes timely corrective actions if past practices have had a negative impact on the environment. Significant resources are dedicated to environmental training, monitoring and compliance. NSP-Minnesota strives to comply with all applicable environmental laws.

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    NSP-Minnesota is potentially liable for remediation of waste disposal sites and for decommissioning and restoration of present and former plant sites. For further discussion of environmental matters, see Note 13 to the Financial Statements.

Permits

    NSP-Minnesota's regulated businesses are required to renew environmental operating permits for their facilities at least every five years. NSP-Minnesota believes that we are in compliance, in all material respects, with environmental permitting requirements.

Waste Disposal

    Spent nuclear fuel storage and disposal issues are discussed in "Nuclear Power—Operation and Waste Disposal" and in Notes 12 and 13 of Notes to Financial Statements.

    NSP-Minnesota has met or exceeded the state and federal removal and disposal requirements for polychlorinated biphenyl (PCB) equipment. NSP-Minnesota has removed nearly all known PCB capacitors from our distribution system, network transformers and equipment in power plants. NSP-Minnesota continues to dispose of PCB-contaminated mineral oil and equipment in accordance with regulations. PCB-contaminated mineral oil is detoxified and reused or burned for energy recovery at permitted facilities. Any future cleanup or remediation costs associated with past PCB disposal practices are unknown at this time.

Air Emissions Control and Monitoring

    In 1994, the U.S. EPA proposed air emission guidelines for municipal waste combustors. To meet the federal and state requirements, NSP-Minnesota has completed installation of additional pollution-control and monitoring equipment at the Red Wing and Wilmarth plants at a cost of $12 million.

    The Clean Air Act calls for reductions in emissions of sulfur dioxide (SO2) and nitrogen oxides (Nox) from electric generating plants. NSP-Minnesota has expended significant amounts over the years to reduce SO2 emissions at our plants. Improvements have been made at the Sherco and King plants to reduce emissions of NOx to comply with Phase II requirements. In 1996, a wet electrostatic precipitator (wet ESP) was installed at Sherco to reduce particulate emissions and lower opacity. NSP-Minnesota has chosen to convert multiple scrubber modules on Sherco units 1 and 2 to the wet ESP design. Capital investment to date for the prototype has been $21 million. NSP-Minnesota estimates total capital expenditures for this project through 2002 will be $46 million.

    In 1997, the EPA revised the National Ambient Air Quality Standards for ozone and fine particulate matter. In 1999, these standards were remanded to the EPA for reconsideration. It is unknown if the EPA will simply try to re-adopt the 1997 standards or propose additional changes. It is anticipated, based on historical monitoring, that NSP-Minnesota will be in compliance with the 1997 standards. However, if the standards change or if an area is determined not to comply with the standards, reductions in SO2 and NOx emissions could be required.

    The Clean Air Act requires the EPA to investigate the impact of air toxic emissions from utilities and, if appropriate, recommend regulations to control those emissions. The EPA delivered a report to Congress in early 1998 that recommended additional investigation of air toxic emissions. The report did not recommend any controls on utility boilers at that time. In 1999, the EPA issued an Information Collection Request (ICR) that required utilities to analyze coal shipments for mercury and share the results with the EPA. In addition, a number of coal-fired units were randomly selected to conduct mercury emissions stack tests. NSP-Minnesota's Sherco Unit 3 was one of the units selected. Testing is scheduled for completion in 2000. The EPA intends to utilize all of the ICR data collected to make a regulatory determination on the need for mercury controls on coal-fired utility boilers by the end of

19

2000. As part of the Minnesota Mercury Reduction Initiative, NSP-Minnesota has been asked to submit to the Minnesota Pollution Control Agency (MPCA) a plan outlining steps the company will take as part of this voluntary effort.

    In 1994, the United Nations Framework Convention on Climate Change was established. In 1997, the Kyoto Protocol was drafted and adopted at the third conference. This Protocol will become effective following ratification by 55 countries, provided those 55 countries account for at least 55 percent of the total carbon dioxide emissions for 1990. Since the Conference at Kyoto, there have been several conferences in which significant progress has been made to turn the broad concepts of Kyoto into working realities, including the development of an action plan. The sixth Conference will meet in November 2000 to continue development of the plan. Although the U.S. has signed the Kyoto Protocol, it must be ratified by the U.S. Senate for the U.S. to become a party to the protocol. If the U.S. becomes a party, the Kyoto Protocol would impose, during the first commitment period of 2008-2012, a binding obligation on the U.S. to reduce greenhouse gas emissions by 7 percent below 1990 levels. Until the details regarding the action plan are completed, the impact on NSP-Minnesota cannot be determined.

Water Quality Monitoring

    To comply with federal and state laws and state regulatory permit requirements, NSP-Minnesota has installed environmental monitoring systems at all coal and RDF ash landfills and coal stockpiles to assess and monitor the impact of these facilities on the quality of ground and surface waters. Degradation of water quality in the state is prohibited by law and requires remedial action for restoration to an acceptable clean-up level.

Electric and Magnetic Fields (EMF)

    EMF surround electric wires and conductors of electricity such as electrical tools, household wiring, appliances, electric distribution lines, electric substations and high-voltage electric transmission lines. Extensive research has been conducted in the last three decades concerning the possibility that adverse health effects may result from exposure to power-frequency fields surrounding transmission and distribution lines and the electrical appliances and devices that are common in residences and workplaces. By 1995, it was generally concluded in the scientific community that there was no consistent evidence that exposure to EMF produced by power lines and electric devices causes cancer or produces other adverse effects on human health. Extensive research studies published since 1995 have reinforced this view. The nation's electric utilities, including NSP-Minnesota, continue to support research in an effort to determine whether exposure to EMF causes health effects.

Contingencies

    Both regulatory requirements and environmental technology change rapidly. NSP-Minnesota cannot estimate the extent to which it may be required by law, in the future, to make additional capital expenditures or incur additional operating expenses for environmental purposes. NSP-Minnesota also cannot predict whether future environmental regulations might result in significant reductions in generating capacity or efficiency or otherwise affect our income, operations or facilities.

CAPITAL SPENDING AND FINANCING

    NSP-Minnesota's capital spending program is designed to assure that there will be adequate generating, transmission and distribution capacity to meet the future needs of its utility service area. We continually reassess needs and, when necessary, appropriate changes are made in the capital expenditure program.

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1999 Financing Requirements

    NSP-Minnesota's need for capital funds primarily is related to the construction of plant and equipment to meet the needs of electric and gas utility customers. Total capital expenditures in 1999 were $348 million. Of that amount, $294 million related to replacements and improvements of NSP-Minnesota's electric system and nuclear fuel, and $34 million involved construction of natural gas facilities.

1999 Financing Activity

    During 1999, NSP-Minnesota's sources of capital included internally generated funds and external financings. The allocation of financing requirements between these capital resources is based on the relative cost of each resource, regulatory restrictions and NSP-Minnesota's long-range capital structure objectives. The following summarizes the financing sources used in 1999.

•

Internal funds—Funds generated internally from operating cash flows in 1999 remained generally sufficient to meet working capital needs, debt service, dividend payout requirements and a significant portion of utility construction expenditures.



•

External financing—NSP-Minnesota's short-term debt availability and usage is described in Note 4 to the Financial Statements. In general, short-term borrowings are used to provide temporary financing, utility capital expenditures, and other short-term cash needs. NSP-Minnesota's long-term debt and divisional equity activity are shown on the Statements of Capitalization and Divisional Equity. These sources are used to provide permanent financing for both regulated and nonregulated business activities.

Future Financing Requirements

    NSP-Minnesota currently estimates that its capital expenditures will be $400 million in 2000 and $1.9 billion for 2000-2004. Of the 2000 amount, approximately $335 million is scheduled for electric utility facilities and approximately $37 million for natural gas facilities. In addition to utility capital expenditures, expected financing requirements for 2000-2004 include approximately $492 million to retire long-term debt and fund principal maturities.

    NSP-Minnesota also will have future financing requirements for the portion of nuclear plant decommissioning costs not funded externally. Based on the most recent decommissioning study approved by regulators, these amounts are anticipated to be approximately $363 million and are expected to be paid during the years 2010-2022.

Future Sources of Financing

    NSP-Minnesota expects to meet future financing requirements by periodically issuing long-term debt, short-term debt and preferred securities or receiving additional equity investment from its parent, Xcel Energy, to maintain desired capitalization ratios. Decommissioning expenses not funded by an external trust will be financed through a combination of internally generated funds, long-term debt and equity contributions from Xcel Energy.

    In addition to internally generated funds, the following summarizes the financing sources expected to be available to NSP-Minnesota in the near future:

•

Short-term debt—NSP-Minnesota has board approval for up to approximately $600 million in short-term borrowing levels. NSP credit lines (as discussed in Note 4 to the Financial Statements) make short-term financing available in the form of bank loans, letters of credit and support for commercial paper.

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•

Long-term debt—NSP-Minnesota's first mortgage indentures limit the amount of first mortgage bonds that may be issued. The MPUC has jurisdiction over securities issuance. At December 31, 1999, with an assumed interest rate of 7.75 percent, NSP-Minnesota could have issued about $1.4 billion of additional first mortgage bonds under its indenture.

EMPLOYEES AND EMPLOYEE BENEFITS

    At year-end 1999, there were 6,273 full- and part-time NSP-Minnesota employees and 5,442 benefit employees. Approximately 2,156 employees are represented by five local International Brotherhood of Electric Workers (IBEW) labor unions.

Union Contract Extension

    In 1999, NSP-Minnesota and the five IBEW local unions representing NSP-Minnesota employees reached agreement on a five-year extension of the collective bargaining agreement. The contract expires at the end of 2004.

Wage increases

    In January 1999, nonbargaining employees received an average wage increase of 4.0 percent, and bargaining employees received a 2.0 percent base wage scale increase. In January 2000, nonbargaining employees received an average wage increase of 4.0 percent and bargaining employees received a 3.5 percent base wage scale increase.

Benefits Changes

    NSP-Minnesota revised its retirement plans for nonbargaining employees (effective January 1999) and bargaining employees (effective January 2000) as follows:

—

The retiree medical plan was discontinued for nonbargaining employees retiring after December 31, 1998, and for bargaining employees retiring after December 31, 1999.



—

The qualified pension plan was enhanced to provide a retirement spending account and enhanced Social Security supplement to use for medical coverage or to supplement pension benefits.



—

The 401(k) plan was enhanced, increasing the amount of employee contributions matched by NSP-Minnesota.

Item 2—Financial Information

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).

Management's Discussion and Analysis

    Following the merger discussed in Item 1, NSP-Minnesota is a wholly-owned subsidiary of Xcel Energy Inc. NSP-Minnesota has the following subsidiaries: United Power and Land Co., a Minnesota corporation (UP&L), First Midwest Auto Park, Inc., a Minnesota corporation (FMAP), NSP Nuclear Corp., a Minnesota corporation, and NSP Financing I, a Minnesota corporation which is a statutory business trust. NSP Nuclear Corp. has a 25 percent ownership in Nuclear Management Co. LLC. The following Management's Discussion and Analysis represents a comparison to results of operations of NSP-Minnesota and its subsidiaries as if the merger occurred as of January 1 of the earliest period presented. It should be read in conjunction with the accompanying Financial Statements and Notes. Discussion of financial condition and liquidity is omitted per conditions set forth in general

22

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 as set forth in general instructions I (2) (a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format). Discussion of year-to-date results through June 30, 2000, is included in Exhibit 99.01.

    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



•

conditions imposed by regulatory agencies in orders approving the merger



•

the items described under "Factors Affecting Results of Operations"



•

the other risk factors listed from time to time by NSP-Minnesota in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.02 to this report.

RESULTS OF OPERATIONS

    Two significant one-time items accounted for a decline in 1999 earnings compared with 1998.

    Conservation Incentive Recovery 1998   In 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 based on this action, which reduced 1999 earnings by $21 million. This charge represented a $32 million reduction in accrued revenue and a reduction of carrying charges.

    Conservation Incentive Recovery 1999   At the end of 1999, the MPUC had not approved a conservation plan for 1999. Based on the change in MPUC policy on conservation incentives and regulatory uncertainty, management decided not to accrue any conservation incentives for 1999 or subsequent years. On Jan. 27, 2000, the MPUC approved a conservation incentive plan under which utilities could earn incentives up to 30 percent of their annual conservation spending. For NSP-Minnesota, the maximum amount of conservation incentives that could be earned is approximately $10 million, with the actual incentive dependent on performance compared with conservation goals. The MPUC also decided that the conservation incentive program is not linked to earnings levels. In addition, the MPUC denied NSP's request to allow rate recovery of load management discounts provided to certain customers.

    NSP's 1998 earnings included approximately $32 million of accrued conservation incentives. Including carrying charges, the reversal of 1998 conservation incentives reduced 1999 earnings by $35 million, a decrease of $67 million compared with incentive recovery levels in 1998. The earnings impacts in 1999 are non-cash accrual adjustments. The cash impacts of conservation incentives collected in rates, including any overcollections for 1998 and 1999, will be addressed in 2000 filings with the MPUC.

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    Weather   In addition to the one-time items above, NSP-Minnesota's earnings has been significantly affected by weather. Very hot summers and very cold winters increase electric and gas sales, but can also increase expenses, which may not be fully recoverable. Unseasonably mild weather can also reduce electric and gas sales. The following summarizes the estimated impact on NSP-Minnesota's earnings due to temperature variations from historical averages for the most recent two years.

•

Weather in 1999 decreased earnings by an estimated $9 million.



•

Weather in 1998 decreased earnings by an estimated $11 million.

Regulated Utility Operating Results

    Electric Revenues   increased $23.4 million or 1.0 percent in 1999 compared with 1998. The increase is primarily due to a 1.6 percent increase in retail sales, fuel cost recovery and a 7.9 percent increase in sales for resale. These increases were partially offset by decreases due to conservation incentive accrual adjustments. The increase in retail sales is primarily due to growth. Sales for resale volumes and revenues increased in 1999 due to the expansion of NSP's wholesale energy marketing operations.

    Electric sales growth for 1999 is listed in the following table on both an actual and weather-normalized basis. NSP's weather-normalization process removes the estimated impact on sales of temperature variations from historical averages.

    Retail electric sales accounted for 85 percent of NSP-Minnesota's electric revenue in 1999. Retail electric sales growth for 2000 is estimated to be 2.5 percent over 1999, or 2.0 percent on a weather-adjusted basis.

    Electric Margin   As shown in the following table, electric margin equals electric revenue minus production expenses.

    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 and the ability to vary wholesale prices with changing market conditions, most fluctuations in energy costs do not affect electric margin. However, during July 1999, NSP-Minnesota's service territory experienced extremely high temperatures, which drove customer usage to record levels. With NSP-Minnesota's power plants operating at maximum available capacity, market conditions forced NSP-Minnesota to purchase the power necessary to serve customer demand at very high costs. NSP-Minnesota's fuel clause billing adjustment process in Minnesota does not allow for the recovery of capacity charges above the levels reflected in base rates. Without the ability to obtain full recovery,

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these unusually high energy and capacity costs reduced electric margin in 1999 as compared with 1998. In total, electric margin decreased $62 million or 4.1 percent in 1999 as compared with 1998. The decrease was primarily due to conservation incentive accrual adjustments and unrecovered demand, fuel and purchased power costs as described above. The decreases were partially offset by retail sales growth and sales for resale.

    Gas Revenues   increased $5.3 million or 1.5 percent in 1999 compared with 1998. The increase is primarily due to weather and growth, partially offset by purchased gas cost adjustments.

    Gas sales growth for 1999 and 1998 is listed in the following tables on both an actual and weather-normalized basis. The majority of NSP-Minnesota's retail gas sales are categorized as firm (primarily heating customers) and interruptible (commercial/industrial customers with an alternate energy supply).

    The 1999 firm sales increase was primarily due to slightly more favorable weather in 1999, compared with 1998, and sales growth. The 1998 firm sales decrease was due to more unfavorable weather in 1998, compared with 1997, partially offset by sales growth. Interruptible sales declined in 1998 because lower alternate fuel prices caused interruptible customers to purchase less natural gas and customers were able to switch to transportation-only service. Firm gas sales in 2000 are estimated to be 15.3 percent higher than 1999 sales, or 1.7 percent higher on a weather-adjusted basis.

    Gas Margin   As shown in the following table, gas margin equals gas revenue less the cost of gas sold.

    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. The increase in gas margin in 1999 as compared with 1998 is primarily due to weather and growth.

    Other Operation, Maintenance and Administrative and General   Expenses decreased in 1999 by $19.1 million, or 2.9 percent, compared with 1998. 1999 expenses decreased primarily due to cost control, including lower employee benefit costs, higher levels of insurance refunds and lower Year 2000 remediation costs.

    Depreciation and Amortization   Costs increased $14.1 million in 1999 compared with 1998 primarily due to higher levels of depreciable plant, including new information systems and equipment with relatively short depreciable lives.

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    Financing Costs   Financing costs were $120.8 million in 1999, $106.4 million in 1998 and $108.2 million in 1997. The 1999 increase is largely due to higher average short-term debt levels to support financing needs. For more information, see the Statements of Capitalization.

    Nonoperating income—including interest income   declined primarily due to less interest income from tax refunds and less allowance for funds used during construction (AFC). AFC decreased primarily due to reductions in carrying charges and other adjustments related to conservation incentive adjustments, as discussed previously, and less construction activity presumed to be financed with equity capital.

    Accounting Change   In June 1998, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." This statement requires that all derivatives be recognized at fair value in the balance sheet and all changes in fair value be recognized currently in earnings or deferred as a component of other comprehensive income, depending on the intended use of the derivative, its resulting designation and its effectiveness.

    In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities, an Amendment to FASB Statement No. 133." This Statement amends SFAS No. 133 in four areas, normal purchases and sales contracts, definition of interest rate risk, hedging recognized foreign currency denominated assets and liabilities and hedging foreign currency risk and intercompany derivatives.

    NSP-Minnesota plans to adopt both of these standards in 2001, as required. NSP-Minnesota has not yet determined the potential impact of implementing these statements.

    NSP-Minnesota's electric generating facilities provided 74 percent of its kwh requirements in 1999. Also, the NSP integrated system generating facilities provided 74 percent of its kwh requirements. The current generating facilities are expected to be adequate base load sources of electric energy until 2003-2006, as detailed in NSP-Minnesota's electric resource plan filed with the MPUC in 1998. All of the NSP integrated system's major generating stations are located in Minnesota on land owned by NSP-Minnesota.

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    At Dec. 31, 1999, NSP-Minnesota had overhead and underground transmission and distribution lines as follows:

    NSP-Minnesota also has approximately 202 transmission and distribution substations with capacities greater than 10,000 kilovoltamperes (kva) and approximately 245 with capacities less than 10,000 kva.

    Manitoba Hydro, Minnesota Power Company and NSP-Minnesota completed the construction of a 500-kv transmission interconnection between Winnipeg, Manitoba, Canada, and the Minneapolis-St. Paul, Minnesota, area in 1980. NSP-Minnesota has a contract with Manitoba Hydro for 500 Mw of firm power utilizing this transmission line. In addition, NSP-Minnesota is interconnected with Manitoba Hydro through a 230-kv transmission line completed in 1970. In 1995, a project was completed to increase the Manitoba-U.S. transmission interconnection by a nominal 400 Mw to 1,900 Mw.

    Plans are currently being implemented for electric delivery system upgrades to accommodate load growth expected in the Minneapolis-St. Paul area through 2010. As the least cost option to accommodate the load growth, portions of the 69-kv transmission facilities, especially those located on the outskirts of the Twin Cities, are being reconductored and operated at 115 kv; distribution development in these areas has been converted to 34.5 kv. By reconductoring on existing right-of-ways and increasing distribution voltage, the requirements for new right-of-ways and substation sites are minimized compared with other distribution substations with capacities greater than alternatives for serving the load growth.

    NSP-Minnesota natural gas mains include approximately 117 miles of transmission mains and approximately 7,826 miles of distribution mains.

    Virtually all of the utility plant of NSP-Minnesota is subject to the lien of its first mortgage bond indentures pursuant to which they have issued first mortgage bonds.

Item 4—Security Ownership of Certain Beneficial Owners and Management

    Omitted.

Item 5—Directors and Executive Officers of the Registrant

    Omitted.

Item 6—Executive Compensation

    Omitted

Item 7—Certain Relationships and Related Transactions

    Omitted.

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Item 8—Legal Proceedings

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

    On Nov. 24, 1998, Wisconsin Electric Power Co. (WE) filed a complaint against NSP-Minnesota with the FERC, relating to transmission service curtailments. In March 1999, NSP-Minnesota and WE reached a settlement agreement, which was approved by the FERC on May 19, 1999. The settlement provides that NSP-Minnesota would not be liable to WE for transmission curtailments during 1998 and NSP-Minnesota would bear certain disputed transmission mitigation costs for 1998 and 1999. The settlement is not material.

    On June 8, 1998, NSP-Minnesota filed a complaint in the Court of Federal Claims against the Department of Energy (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 filed a notice of appeals with the Federal Circuit and on July 20, 1999, NSP-Minnesota filed its initial brief on appeal. On August 31, 2000, the Federal Circuit reversed the dismissal by the Court of Federal Claims and remanded the case to the Court of Federal Claims.

    On August 7, 1998, a group of residential and commercial customers brought a class action lawsuit against the DOE in the Federal District Court in Minneapolis, Minn. The suit demands the return of monies paid by customers into the nuclear waste fund and other damages, based on the failure of the DOE to meets its unconditional obligation to accept spent nuclear fuel by January 31, 1998. NSP-Minnesota is named as nominal defendant because NSP-Minnesota has the contract with the DOE under which payments are made into the fund. On December 23, 1999, the Court dismissed the class action suit.

    For a discussion of other legal claims, see "Legal Claims" in Note 13 to the Financial Statements included in this filing. For a discussion of environmental proceedings, see "Environmental Matters" under Item 1 included in this filing. For a discussion of proceedings involving NSP's utility rates, see "Utility Regulation and Revenues" and "Gas Utility Operations" under Item 1 included in this filing.

Item 9—Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters

    All of the outstanding Common Stock of NSP-Minnesota is, as of the date hereof, owned by Xcel Energy Inc. There is no market for the Common Stock. Dividends on the Common Stock will be paid when declared by the Board of Directors of NSP-Minnesota.

Item 10—Recent Sales of Unregistered Securities

     None.

Item 11—Description of Registrant's Securities to be Registered

    NSP-Minnesota's Articles of Incorporation authorize the issuance of 5,000,000 shares of common stock, par value $0.01 per share. As of August 18, 2000, 1,000,000 shares of its common stock were issued and outstanding, all of which are owned by Xcel Energy Inc. and were duly and validly issued and fully paid and non-assessable. Holders of common stock are entitled to one vote per share on all matters voted on by stockholders. The Articles of Incorporation do not provide for cumulative voting in the election of directors. The holders of common stock have no preemptive, redemption or conversion

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rights and are not liable for any calls or assessments. Holders of the common stock of NSP-Minnesota are entitled to receive such dividends as may be declared from time to time by the Board of Directors from funds available therefore, and upon liquidation shall be entitled to receive pro rata all assets of NSP-Minnesota available for distribution.

    In our Trust Indenture dated February 1, 1937, as supplemented (the Trust Indenture), securing our First Mortgage Bonds, we have agreed that the sum of:

•

all dividends and distributions on the common stock after Sept. 30, 1954 (other than in common stock), and



•

the cost of all shares of common stock acquired by us after that date

will not exceed the sum of (a) the earned surplus of NSP-Minnesota and certain of our former subsidiary companies consolidated, at Sept. 30, 1954, and (b) the net income earned after Sept. 30, 1954, after adjusting for all preferred stock dividends after that date and all proper charges and credits to earned surplus made after that date. In computing net income for this purpose, if 15 percent of the consolidated gross operating revenues of such companies exceeds the aggregate of the amounts expended for maintenance and provided for depreciation, such excess will be deducted from net income. These provisions are not expected to impair our ability to pay dividends in the foreseeable future.

    Our Supplemental and Restated Trust Indenture dated May 1, 1988 (the Restated Indenture) amends and restates the Trust Indenture. The Restated Indenture will not become effective and operative until all First Mortgage Bonds of each series issued under the Trust Indenture prior to July 1989 have been retired or, subject to certain limitations, until the holders of the requisite principal amount of such First Mortgage Bonds shall have consented to the amendments contained in the Restated Indenture (the Effective Date). The Restated Indenture will replace the dividend restriction described in the preceding paragraph with the requirement that:

•

the sum of: (i) all dividends and distributions on the common stock after the Effective Date (other than in common stock), and (ii) the net payments for common stock after the Effective Date (i.e., the amount, if any, by which the payments made for the purchase or other acquisition of our common stock after the Effective Date exceeds the considerations received by us after the Effective Date from the sale of common stock)



•

will not exceed the sum of (i) the retained earnings of NSP-Minnesota at the Effective Date, and (ii) an amount equal to the net income of NSP-Minnesota earned after the Effective Date, after deducting all preferred stock dividends after the Effective Date.

    In computing net income for the purpose of this amended covenant, we will deduct the amount, if any, by which, the actual expenditures or charges for ordinary repairs and maintenance and the charges for reserves, renewals, replacements, retirements, depreciation and depletion since one year before the Effective Date are less than 2.50 percent of our completed depreciable property.

Item 12—Indemnification of Directors and Officers

    Section 302.A.521 of Minnesota Statues permits indemnification of officers and directors of domestic or foreign corporations under certain circumstances and subject to certain limitations. The Bylaws of NSP-Minnesota contain provisions for indemnification of its directors and officers consistent with the provisions of Section 302A.521 of the Statutes. NSP-Minnesota's Articles of Incorporation also contain provisions limiting the liability of the directors in certain instances.

    NSP-Minnesota has obtained insurance policies indemnifying NSP-Minnesota and NSP-Minnesota's directors and officers against certain civil liabilities and related expenses.

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Item 13—Financial Statements and Supplementary Data

    See Exhibit 99.01 for balance sheets and income statements for the six-month periods ended June 30, 2000 and June 30, 1999.

    See Item 15(a) for index of financial statements included herein.

    See Note 15 to of Notes to Financial Statements for summarized quarterly financial data.

Report of Independent Accountants

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 each of the three years in the period ended December 31, 1999 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.

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

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See Notes to Financial Statements

31

See Notes to Financial Statements

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