NORTHERN STATES POWER CO, 10-12G/A, 2000-12-07

NORTHERN STATES POWER CO
10-12G/A, 2000-12-07
ELECTRIC & OTHER SERVICES COMBINED

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10/A

GENERAL FORM FOR REGISTRATION OF SECURITIES
PURSUANT TO SECTION 12(b) OR 12(g) OF
THE SECURITIES EXCHANGE ACT OF 1934

NORTHERN STATES POWER COMPANY
(Exact Name of Registrant as Specified in Its Charter)

MINNESOTA (State or Other Jurisdiction of Incorporation or Organization)		41-1967505 (IRS Employer I.D. No.)
414 Nicollet Mall, Minneapolis, Minnesota (Address of Principal Executive Offices)		55401 (Zip Code)

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

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

Title of Each Class to be so Registered		Name of Each Exchange on Which Each Class is to be Registered
None		Not Applicable

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.

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.

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:

		Authorized Return on Common Equity at December 31, 1999
		Authorized Return on Common Equity at December 31, 1999				Percent of Total 1999 Utility Revenues (Electric & Gas)
		Electric		Gas		Percent of Total 1999 Utility Revenues (Electric & Gas)
Retail:
Minnesota Public Utilities Commission		11.47	%	11.4%	**	89.4	%
North Dakota Public Service Commission		11.5		12.0	**	6.0
South Dakota Public Utilities Commission		*				3.9
Sales for Resale—Wholesale and Interstate Transmission: Federal Energy Regulatory Commission		*		*		0.7
	Total					100	%

*: 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)

	Annual Increase/(Decrease)
Year	Requested			Granted
	(Millions of dollars)
1995	$	(0.8	)	$	(0.8	)
1996		(0.5	)		(0.5	)
1997		—			—
1998		18.5			13.4
1999		0.3			0.3

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.

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.

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

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.

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

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

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.

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.

Energy Sources

During 1999, 44 percent of NSP-Minnesota's kwh requirements were obtained from coal generation and 29 percent were obtained from nuclear generation. Purchased and interchange energy provided 26 percent, including 10 percent from Manitoba Hydro; our hydro and other fuels provided the remaining 1 percent. The following is a summary of NSP-Minnesota's electric power output in millions of kwh for the past three years:

		1999	1998	1997
Thermal plants		33,396	32,096	31,345
Hydro plants		77	82	83
Purchased and interchange and other plants		12,140	12,770	11,156

	Total	45,613	44,948	42,584

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.

Fuel Supply and Costs

Coal and nuclear fuel will continue to dominate NSP-Minnesota's regulated utility fuel requirements for generating electricity by NSP-Minnesota-owned generating capacity. The actual fuel mix for 1999 and the estimated fuel mix for 2000 and 2001 are as follows:

	Fuel Use on Btu Basis
	1999		(Est) 2000		(Est) 2001
Coal	63.1	%	59.4	%	59.5	%
Nuclear	34.6	%	37.3	%	37.5	%
Other	2.3	%	3.3	%	3.0	%

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:

Plant	Maximum Annual Requirements	Amount Covered by Contract in 2000	Contract Expiration Date
	(Tons)	(Tons)
Black Dog	1,000,000	1,000,000	(1)
High Bridge	800,000	800,000	(1)
Allen S. King	2,000,000	2,000,000	(1)
Riverside	1,400,000	1,400,000	(1)
Sherco	7,700,000	7,700,000	(1)

	12,900,000	12,900,000

(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.

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:

	Fuel Costs Per Million Btu
	1997		1998		1999
Coal*	$	1.11	$	1.06	$	1.09
Nuclear		.47		.47		.48
Composite All Fuels		.91		.87		.87

*: 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

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.

Electric Operating Statistics

The following table summarizes the revenues, sales and customers from NSP-Minnesota's electric utility business.

			1999			1998		1997		1996		1995
Revenues (thousands)
	Residential		$	682,783		$	653,625	$	622,194	$	608,588	$	614,670
	Small commercial and industrial			344,245			330,526		323,748		322,297		307,694
	Medium commercial and industrial			424,764			404,945		370,323		347,315		349,637
	Large commercial and industrial			443,936			424,337		416,578		394,315		387,579
	Streetlighting and other			27,268		$	26,800		26,516		25,663		24,841
	Conservation accrual adjustments*			(71,348	)

		Total retail	$	1,851,648		$	1,840,233	$	1,759,359	$	1,698,178	$	1,684,421
	Sales and resale			152,442			133,953		91,986		81,570		116,058
	Transmission and other			263,123			269,587		249,895	$	227,011		219,352

		Total	$	2,267,213		$	2,243,773	$	2,101,240	$	2,006,759	$	2,019,831

Sales (millions of kilowatt-hours)
	Residential			8,642			8,420		8,109		8,140		8,236
	Small commercial and industrial			5,163			5,060		5,010		5,195		4,880
	Medium commercial and industrial			7,718			7,581		6,938		6,415		6,549
	Large commercial and industrial			9,837			9,804		9,795		9,679		9,501
	Streetlighting and other			285			286		294		293		288

		Total retail		31,645			31,151		30,146		29,722		29,454
	Sales for resale			6,252			5,842		4,203		4,472		6,044

		Total		37,897			36,993		34,349		34,194		35,498

Customer accounts (at Dec. 31)**
	Residential			1,115,974			1,099,103		1,088,240		1,073,330		1,057,425
	Small commercial and industrial			131,154			126,500		121,543		118,315		116,708
	Medium commercial and industrial			8,327			8,112		7,795		6,701		6,657
	Large commercial and industrial			662			634		605		589		579
	Streetlighting and other			5,330			5,232		5,271		4,081		3,883

		Total retail		1,261,447			1,239,581		1,223,454		1,203,016		1,185,252
	Sales for resale			72			68		49		44		56

		Total		1,261,519			1,239,649		1,223,503		1,203,060		1,185,308

*: 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.

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.

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:

Northern Natural Gas Company		Northern Border Pipeline Company
Williston Basin		ANR Pipeline Company
Viking Gas Transmission		TransCanada Gas Pipeline Ltd.
Great Lakes

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.

	Average Cost/mmBtu
1997	$	3.33
1998	$	2.87
1999	$	2.86

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.

Gas Operating Statistics

The following table summarizes the revenue, sales and customers from NSP-Minnesota's regulated natural gas businesses.

			1999		1998		1997		1996		1995
Revenues (thousands)
	Residential		$	196,190	$	187,736	$	213,076	$	225,748	$	178,292
	Commercial and industrial
		Firm		102,722		99,293		118,447		119,531		93,244
		Interruptible		47,848		45,386		57,986		45,521		33,730
	Other			1,495		4,721		3,882		970		1,849

		Total Retail	$	348,255	$	337,136	$	393,391	$	391,770	$	307,115
	Agency, transportation and off-system sales			17,580		23,432		21,468		34,809		28,967

		Total	$	365,835	$	360,568	$	414,859	$	426,579	$	336,082

Sales (thousands of mmBtu)
	Residential			34,478		31,949		36,580		41,692		36,421
	Commercial and industrial
		Firm		21,379		19,832		22,881		25,327		22,149
		Interruptible		18,062		17,769		19,428		16,757		16,182
	Other			1,691		3,327		1,461		408		1,525

		Total Retail		75,610		72,877		80,350		84,184		76,277

Other gas delivered (thousands of mmBtu)
	Agency, transportation and off-system sales			12,463		14,337		11,705		15,920		19,701

Customer accounts (as Dec. 31)*
	Residential			368,468		351,459		342,142		333,567		322,831
	Commercial and industrial			40,383		33,891		33,095		31,655		30,198

		Total Retail		408,851		385,350		375,237		365,222		353,029
	Other gas delivered			51		49		36		30		62

		Total		408,902		385,399		375,273		365,252		353,091

*: 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.

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

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.

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.

•: 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

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 September 30, 2000, is included in Exhibit 99.01, which is incorporated herein by reference.

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.

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.

	1999 vs 1998
Sales Growth	Actual		Weather-Normalized
Residential	2.6	%	3.0	%
Commercial & industrial	1.2	%	1.3	%
Total retail	1.6	%	1.8	%
Sales for resale	7.9	%	na
Total Electric Sales	2.6	%	na

na = not applicable

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.

(Millions of dollars)	1999			1998			1997
Electric revenue	$	2 267		$	2 244		$	2 101
Fuel for electric generation		(309	)		(300	)		(300	)
Purchased and interchange power		(502	)		(426	)		(334	)

Electric Margin	$	1 456		$	1 518		$	1 467

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,

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).

	1999 vs 1998
Sales Growth	Actual		Weather-Normalized
Total firm	7.9	%	0.9	%
Interruptible	1.6	%	na
Total retail	3.8	%	na
Transportation & other	(13.1	)%	na
Total Gas Sales and Delivery	1.0	%	na

na = not applicable

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.

(Millions of dollars)	1999			1998			1997
Gas revenue	$	366		$	361		$	415
Cost of gas purchased and transported		(230	)		(226	)		(281	)

Gas margin	$	136		$	135		$	134

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.

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. Based on the review discussed below, management currently expects the impact of implementing these statements to be immaterial to results of operations and financial condition of NSP-Minnesota.

NSP-Minnesota has reviewed its commodity, energy and other related contracts for purposes of identifying derivative instruments. We are nearly complete with the process of designating contracts that qualify for the normal purchase and sales exception, determining fair market values for derivatives, designating and documenting hedge relationships, and evaluating the effectiveness of those hedging relationships. We are completing this review under the current SFAS 133 standards and interpretations. However, the results of this review may need to be reevaluated based on the deliberations and interpretations expected from the FASB in the fourth quarter of 2000, regarding the final implementation guidance for SFAS 133. Pending this review, the actual impact of NSP-Minnesota's adoption of SFAS 133 is uncertain at this time and will vary based on factors such as specific derivative and hedging activities, market conditions and contractual arrangements at the date of adoption.

Item 3—Properties

NSP-Minnesota's major electric generating facilities consist of the following:

Station and Unit		Fuel	Installed	1999 Summer Capability (Mw)	1999 Output (Millions of kwh)
Sherburne
	Unit 1	Coal	1976	712	3 911
	Unit 2	Coal	1977	721	4 735
	Unit 3	Coal	1987	514	3 170
Prairie Island
	Unit 1	Nuclear	1973	526	4 649
	Unit 2	Nuclear	1974	526	4 069
Monticello		Nuclear	1971	578	4 598
King		Coal	1968	571	3 296
Black Dog
	4 Units	Coal/Natural Gas	1952-1960	462	1 383
High Bridge
	2 Units	Coal	1956-1959	267	1 187
Riverside
	2 Units	Coal	1964-1987	380	2 155
Other		Various	Various	1054	574

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.

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

Voltage		Length (Pole Miles)
500kv		265
345kv		568
230kv		284
161kv		59
115kv		1,189
Less than 115kv		38,892

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.

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.

On Dec. 11, 1998, a gas explosion in St. Cloud, Minn., killed four people, including two NSP-Minnesota employees, injured approximately 14 people and damaged several buildings. The accident occurred as a crew from Cable Constructors Inc. (CCI) was installing fiber optic cable for Seren, a subsidiary of Xcel Energy. Seren, CCI and Sirti, an architecture/engineering firm retained by Seren, are named as defendants in 10 lawsuits relating to the explosion. NSP-Minnesota is a defendant in eight of the law suits. NSP-Minnesota and Seren deny any liability for this accident. On July 11, 2000, the National Transportation Safety Board issued a report, which determined that CCI's inadequate installation procedures and delay in reporting the gas hit were the proximate cause of the accident. NSP-Minnesota has a self-insured retention deductible of $2 million with general liability coverage limits of $185 million. Seren's primary insurance coverage is $1 million and its secondary insurance coverage is $185 million. The ultimate cost to NSP-Minnesota and Seren, if any is presently unknown.

In April 1997, a fire damaged several buildings in downtown Grand Forks, N.D., during a flood in the city. On July 23, 1998, the St. Paul Mercury Insurance Co. commenced a lawsuit against NSP-Minnesota for damages in excess of $15 million. The suit was filed in the District Court in Grand Forks County in North Dakota. The insurance company alleges the fire was electrical in origin and that NSP-Minnesota was legally responsible for the fire because it failed to shut off electrical power to downtown Grand Forks during the flood and prior to the fire. Seven additional lawsuits were filed against NSP-Minnesota by insurance companies that insured businesses damaged by the fire. One additional lawsuit filed by the First National Bank of Grand Forks is venued in Federal Court. The total of damages being sought by all these lawsuits is in excess of $30 million. NSP-Minnesota denied any liability, asserting that it was not legally responsible for this unforeseeable event. Trial concerning the state court lawsuits commenced on Aug. 1, 2000, and concluded on Sept. 7, 2000. On Sept. 8, 2000, after deliberating for only one hour, a jury returned a defense verdict in favor of NSP-Minnesota. It is unknown whether the plaintiffs will appeal. NSP-Minnesota has a self-insured retention deductible of $2 million, with general liability insurance coverage limits of $150 million. The ultimate cost to Xcel Energy and NSP-Minnesota, if any, is unknown at this time.

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 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.

Item 13—Financial Statements and Supplementary Data

See Exhibit 99.01, which is incorporated herein by reference, for balance sheets and income statements for the nine-month periods ended September 30, 2000 and September 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

Consolidated Statements of Income

			Year Ended Dec. 31
(Thousands of dollars)			1999			1998			1997
Utility Operating Revenues
	Electric		$	2 267 213		$	2 243 773		$	2 101 240
	Gas			365 835			360 568			414 859

	Total			2 633 048			2 604 341			2 516 099

Operating Expenses
	Fuel for electric generation			309 252			300 013			299 976
	Purchased and interchange power			502 208			426 315			334 359
	Cost of gas purchased and transported			229 913			225 956			280 964
	Other operation and maintenance			537 548			537 021			498 960
	Administrative and general			105 929			125 564			122 022
	Conservation and energy management			55 059			63 281			62 004
	Depreciation and amortization			310 129			296 059			286 494
	Property and general taxes			204 755			203 562			211 824

	Total			2 254 793			2 177 771			2 096 603

Operating Income				378 255			426 570			419 496

Other Income (Expense)
	Nonoperating income—including interest income			10 135			26 074			14 655
	Nonoperating expenses			(11 205	)		(11 353	)		(4 675	)

	Total			(1 070	)		14 721			9 980

Income before interest charges and income taxes				377 185			441 291			429 476

Financing costs
	Interest on long-term debt			83 621			85 011			82 782
	Other interest and amortization			26 060			12 399			20 708
	Allowance for funds used during construction—debt			(4 657	)		(6 788	)		(9 681	)

	Total interest charges			105 024			90 622			93 809
	Distributions on redeemable preferred securities of subsidiary trust			15 750			15 750			14 438

		Total Financing Costs		120 774			106 372			108 247

Income before income taxes				256 411			334 919			321 229
Income taxes				97 431			124 713			121 764

Net Income			$	158 980		$	210 206		$	199 465

See Notes to Financial Statements

Consolidated Statements of Cash Flows

			Year Ended Dec. 31
(Thousands of dollars)			1999			1998			1997
Cash Flows from Operating Activities
	Net income		$	158 980		$	210 206		$	199 465
	Adjustments to reconcile net income to cash from operating activities:
		Depreciation and amortization		327 415			313 485			302 954
		Nuclear fuel amortization		50 056			43 816			40 015
		Deferred income taxes		(9 729	)		(12 841	)		(1 483	)
		Deferred investment tax credits recognized		(8 324	)		(9 023	)		(8 925	)
		Allowance for funds used during construction—equity		300			(8 106	)		(5 924	)
		Conservation incentive adjustments—noncash		71 348
		Cash provided by (used for) changes in certain working capital items		(72 390	)		10 223			40 514
		Cash provided by (used for) changes in other assets and liabilities		38 893			23 810			(1 653	)

Net Cash Provided by Operating Activities				556 549			571 570			564 963

Cash Flows from Investing Activities
	Capital expenditures:
		Utility plant additions (including nuclear fuel)		(348 469	)		(336 256	)		(317 739	)
		Nonregulated property additions		(1 427	)		(4 149	)		(766	)
	Increase (decrease) in construction payables			(5 892	)		4 732			1 664
	Allowance for funds used during construction—equity			(300	)		8 106			5 924
	Investment in external decommissioning fund			(39 183	)		(41 360	)		(41 261	)
	Other investments—net			(6 002	)		(1 869	)		(2 134	)

Net Cash Used for Investing Activities				(401 273	)		(370 796	)		(354 312	)

Cash Flows from Financing Activities
	Change in short-term debt—net issuances (repayments)			305 920			(24 079	)		(223 579	)
	Proceeds from issuance of long-term debt—net			264 829			251 032
	Repayment of long-term debt, including reacquisition premiums			(224 283	)		(109 669	)		(103 235	)
	Proceeds from issuance of preferred securities—net									193 315
	Capital distributions to parent			(510 523	)		(318 909	)		(75 829	)

Net Cash Used for Financing Activities				(164 057	)		(201 625	)		(209 328	)

Net Increase (Decrease) in Cash and Cash Equivalents				(8 781	)		(851	)		1 323
Cash and cash equivalents at beginning of period				20 125			20 976			19 653

Cash and Cash Equivalents at End of Period			$	11 344		$	20 125		$	20 976

Cash Provided by (Used for) Changes in Certain Working Capital Items
	Customer accounts receivable and unbilled utility revenues		$	(18 109	)	$	(41 596	)	$	56 517
	Materials and supplies inventories			(7 672	)		(3 547	)		(4 070	)
	Payables and accrued liabilities (excluding construction payables)			(46 530	)		49 711			(24 368	)
	Other			(79	)		5 655			12 435

		Net	$	(72 390	)	$	10 223		$	40 514

Supplemental Disclosures of Cash Flow Information:
	Cash paid during the year for:
		Interest (net of amount capitalized)	$	114 016		$	96 455		$	104 964
		Income taxes (net of refunds received)	$	115 329		$	82 639		$	132 505

See Notes to Financial Statements

Consolidated Balance Sheets

				Dec. 31
(Thousands of dollars)				1999			1998
Assets
Utility Plant
	Electric—including construction work in progress: 1999, $76,156; 1998, $97,325			$	6 396 370		$	6 227 401
	Gas				636 444			601 533
	Other				287 332			284 061

			Total		7 320 146			7 112 995
		Accumulated provision for depreciation			(3 827 746	)		(3 609 874	)
	Nuclear fuel—including amounts in process: 1999, $13,708; 1998, $16,744				1 026 063			975 030
		Accumulated provision for amortization			(923 336	)		(873 281	)

			Net utility plant		3 595 127			3 604 870
Current Assets
	Cash and cash equivalents				11 344			20 125
	Customer accounts receivable—net of accumulated provisions for uncollectible accounts: 1999, $5,503; 1998, $3,949				184 644			193 655
	Unbilled utility revenues				122 493			118 087
	Receivables from affiliated companies				110 870			84 386
	Other receivables				51 812			55 437
	Materials and supplies inventories—at average cost:
		Fuel			51 514			46 131
		Other			101 678			99 326
	Prepayments and other				50 141			19 549

			Total current assets		684 496			636 696

Other Assets
	External decommissioning fund				517 129			438 981
	Regulatory assets				208 176			288 479
	Nonregulated property—net of accumulated depreciation: 1999, $27,479; 1998, $24,632				42 888			44 268
	Other investments and receivables				40 851			53 351
	Long-term prepayments and deferred charges				79 039			39 701

			Total other assets		888 083			864 780

Total				$	5 167 706		$	5 106 346

See Notes to Financial Statements

Consolidated Balance Sheets

			Dec. 31
(Thousands of dollars)			1999		1998
Liabilities and Divisional Equity
Capitalization (See Consolidated Statements of Capitalization)
	Divisional equity		$	1 186 095	$	1 530 972
	Mandatorily redeemable preferred securities of subsidiary trust			200 000		200 000
	Long-term debt			1 186 586		1 050 167

		Total capitalization		2 572 681		2 781 139

Current Liabilities
	Long-term debt due within one year			114 118		212 084
	Other long-term debt potentially due within one year			141 600		141 600
	Short-term debt—primarily commercial paper			420 193		114 273
	Accounts payable			210 952		242 906
	Taxes accrued			162 748		182 969
	Interest accrued			31 299		29 056
	Capital distributions payable to parent (Xcel Energy)			57 523		55 650
	Accrued payroll, vacation and other			88 719		58 039

		Total current liabilities		1 227 152		1 036 577

Other Liabilities
	Deferred income taxes			681 431		682 515
	Deferred investment tax credits			100 105		108 871
	Regulatory liabilities			439 717		350 165
	Postretirement and other benefit obligations			112 139		111 342
	Other long-term obligations and deferred income			34 481		35 737

		Total other liabilities		1 367 873		1 288 630

Commitments and Contingent Liabilities (See Notes 12 and 13)
Total			$	5 167 706	$	5 106 346

See Notes to Financial Statements

Consolidated Statements of Divisional Equity

(Thousands of dollars)	Other Divisional Equity			Retained Earnings			Leveraged ESOP			Total Divisional Equity
Balance at Dec. 31, 1996	$	496 242		$	1 041 683		$	(19 091	)	$	1 518 834

Net income					199 465						199 465
Capital distributions from (to) parent		103 357			(182 546	)					(79 189	)
Repayment of ESOP loan								8 558			8 558

Balance at Dec. 31, 1997		599 599			1 058 602			(10 533	)		1 647 668

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

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

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

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

See Notes to Financial Statements

Consolidated Statements of Capitalization

				Dec. 31
(Thousands of dollars)				1999			1998
Divisional Equity
	Divisional equity			$	145 613		$	462 080
	Retained earnings				1 052 088			1 087 395
	Leveraged common stock held by Employee Stock Ownership Plan (ESOP) Former NSP shares at cost: 1999,392,325; 1998, 641,884				(11 606	)		(18 503	)

		Total divisional equity		$	1 186 095		$	1 530 972

Mandatorily Redeemable Preferred Securities of Subsidiary Trust holding as its sole asset junior subordinated deferrable debentures of NSP-Minnesota 7 7/8% series, 8,000,000 shares due Jan. 31, 2037—(See Note 2)				$	200 000		$	200 000

Long-Term Debt
	First Mortgage Bonds—NSP-Minnesota Series due:
		Feb. 1, 1999, 5 1/2%					$	200 000
		Dec. 1, 2000, 5 3/4%		$	100 000			100 000
		Oct. 1, 2001, 7 7/8%			150 000			150 000
		April 1, 2003, 6 3/8%			80 000			80 000
		Dec. 1, 2005, 6 1/8%			70 000			70 000
		Dec. 1, 1999-2006, 6.00%-6.75%						16 900	(a)
		Dec. 1, 1999-2006, 3.50-4.10%			15 170	(a)
		March 1, 2011, Variable Rate			13 700	(b)		13 700	(b)
		July 1, 2025, 7 1/8%			250 000			250 000
		April 1, 2007, 6.80%			60 000	(b)		60 000	(b)
		March 1, 2019, Variable Rate			27 900	(b)		27 900	(b)
		Sept. 1, 2019, Variable Rate			100 000	(b)		100 000	(b)
		March 1, 2003, 5 7/8%			100 000			100 000
		March 1, 2028, 6 1/2%			150 000			150 000

			Total		1 116 770			1 318 500
Less redeemable bonds classified as current (See Note 5)					(141 600	)		(141 600	)
Less current maturities					(101 940	)		(201 600	)

			Net	$	873 230		$	975 300

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

See Notes to Financial Statements

			Dec. 31
(Thousands of dollars)			1999			1998
Long-Term Debt—continued
	Guaranty Agreements—NSP-Minnesota Series due:
		Feb. 1, 1999-2003, 5.41%	$	4 900	(b)	$	5 100	(b)
		May 1, 1999-2003, 5.70%		22 250	(b)		22 750	(b)
		Feb. 1, 2003, 7.40%		3 500	(b)		3 500	(b)

		Total		30 650			31 350
	Less current maturities			(700	)		(700	)

		Net	$	29 950		$	30 650

Other Long-Term Debt
	NSP-Minnesota Senior Notes Due Aug. 1, 2009, 6 7/8%		$	250 000
	City of Becker Pollution Control Revenue Bonds—Series due Dec. 1, 2005, 7.25%			9 000	(b)	$	9 000	(b)
	Anoka County Resource Recovery Bond—Series due Dec. 1, 1999-2008, 6.70%-7.15%						20 600	(a)
	Anoka County Resource Recovery Bond—Series due Dec. 1, 2000-2008, 3.95%-4.60%			19 615	(a)
	United Power & Land Notes due March 31, 2000, 7.62%			5 208			6 041
	First Midwest Auto Park Note due Dec. 31, 2003 6.42%			4 600			5 000
	Employee Stock Ownership Plan Bank Loans due 1999-2005, Variable Rate			11 606			18 503
	Miscellaneous			1 458			136

		Total		301 487			59 280
	Less current maturities			(11 477	)		(9 784	)

		Net	$	290 010		$	49 496

Unamortized discount on long-term debt-net				(6 604	)		(5 279	)

		Total long-term debt	$	1 186 586		$	1 050 167

		Total capitalization	$	2 572 681		$	2 781 139

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

See Notes to Financial Statements

Northern States Power Company-Minnesota (Consolidated),
a Subsidiary of Xcel Energy Inc.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Merger and Basis of Presentation—Northern States Power Company (formerly Northern Power Corporation and hereinafter NSP-Minnesota) was incorporated in 2000 under the laws of Minnesota. 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). The merger was a tax-free, stock-for-stock exchange for shareholders of both companies and was accounted for as a pooling of interests. 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's common shares have a par value of $0.01 per share. On March 8, 2000, 5,000,000 shares were authorized and on Aug. 18, 2000, 1,000,000 shares were issued and outstanding.

Business and System of Accounts—NSP-Minnesota is primarily a public utility serving customers in Minnesota, North Dakota and South Dakota. The accounting records conform to the Federal Energy Regulatory Commission (FERC) uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material aspects.

Principles of Consolidation—The following wholly owned subsidiaries of NSP-Minnesota are included in the consolidated financial statements.

•: United Power and Land Co.
•: First Midwest Auto Park, Inc.
•: NSP Nuclear Corporation
•: NSP Financing I

NSP-Minnesota uses the equity method of accounting for its investments in joint ventures. In the consolidation process, we eliminate all significant intercompany transactions and balances except for intercompany and intersegment profits for sales among the electric and gas utility businesses of NSP-Minnesota, which are allowed in utility rates.

Revenues—NSP-Minnesota records utility revenues based on a calendar month, but reads meters and bills customers according to a cycle that doesn't necessarily correspond with the calendar month's

end. To compensate, we estimate and record unbilled revenues from the monthly meter-reading dates to the month's end. NSP-Minnesota's rates include monthly adjustments for:

•: changes in the average cost of fuel, including electricity and natural gas that NSP-Minnesota purchases, from base levels approved in the most recent rate case; and
•: recovery of conservation and energy management program costs and incentives in Minnesota, which is reviewed annually.

Service Company Costs—After the formation of Xcel Energy, Xcel Services will allocate all of its costs for corporate and administrative services to Xcel Energy-owned entities. Through 1999, all of these corporate and administrative services resided in Former NSP, net of amounts allocated to former NSP subsidiaries as appropriate. We believe these residual embedded costs are a reasonable estimate of the corporate and administrative costs allocable to NSP-Minnesota, although future cost allocations from Xcel Services may be calculated on a slightly different basis.

Utility Plant and Retirements—Utility plant is stated at original cost. The cost of utility plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of utility plant retired, plus net removal cost, is charged to accumulated depreciation and amortization. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses.

Allowance for Funds Used During Construction (AFC)—AFC, a noncash item, represents the cost of capital used to finance utility construction activity. AFC is computed by applying a composite pretax rate to qualified construction work in progress. The AFC rate was 5.25 percent in 1999 and 8.0 percent in 1998. The amount of AFC capitalized as a construction cost is credited to other income (for equity capital) and interest charges (for debt capital). AFC amounts capitalized are included in NSP-Minnesota's rate base for establishing utility service rates. In addition to construction-related amounts, AFC is also recorded to reflect returns on capital used to finance conservation programs.

Depreciation—NSP-Minnesota determines the depreciation of its plant by spreading the original cost equally over the plant's useful life. Every five years, NSP-Minnesota submits an average service life filing to the Minnesota Public Utilities Commission (MPUC) for electric and gas property. The most recent filing occurred in 1997. Depreciation expense as a percentage of the average utility plant in service was 3.89 percent in 1999, 3.83 percent in 1998 and 3.84 percent in 1997.

Decommissioning—NSP-Minnesota accounts for the future cost of decommissioning—or permanently retiring—its nuclear generating plants through annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning costs. Our decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends over the estimated lives of the plants. The calculation assumes that NSP-Minnesota will recover those costs through rates. See Note 12 for more information on decommissioning.

Nuclear Fuel Expense—Nuclear fuel expense, which is recorded as the plant uses fuel, includes the cost of:

•: nuclear fuel used

•: future spent nuclear fuel disposal, based on fees established by the U.S. Department of Energy (DOE)
•: NSP-Minnesota's portion of the cost of decommissioning or shutting down the DOE's fuel enrichment facility

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

We record estimated remediation costs, excluding inflationary increases and possible reductions for insurance coverage and rate recovery. The estimates are based on our experience, our assessment of the current situation and the technology currently available for use in the remediation.

We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated responsible parties, we estimate and record only our share of the cost. We treat any future costs of restoring sites where operation may extend indefinitely as a capitalized cost of plant retirement. The depreciation expense levels we can recover in rates include a provision for these estimated removal costs.

Income Taxes—Based on the liability method, NSP-Minnesota defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. We use the tax rates that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, we account for the reversal of some temporary differences as current income tax expense. We defer investment tax credits and spread their benefits over the estimated lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which we summarize in Note 10.

Derivative Financial Instruments—NSP-Minnesota's Energy Marketing division uses future and forward contracts to manage the risk of natural gas and electricity price fluctuations and its impact on margins. The cost or benefit of futures or forward contracts is recorded when related sales commitments are fulfilled as a component of operating expenses. NSP-Minnesota does not speculate in electricity or natural gas futures. For information on derivatives, see Note 8.

Use of Estimates—In recording transactions and balances resulting from business operations, NSP-Minnesota uses estimates based on the best information available. We use estimates for such items as plant depreciable lives, tax provisions, uncollectible amounts, environmental costs, unbilled revenues and actuarially determined benefit costs.

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

Investments in Marketable Securities—NSP-Minnesota has three types of investments in marketable securities. Two of these, cash equivalents and short-term investments, are intended to be

held to maturity and are carried at cost which approximates market value. NSP-Minnesota considers investments in certain debt instruments—with a remaining maturity of three months or less at the time of purchase—to be cash equivalents. Those debt instruments are primarily commercial paper and money market funds. The third type, investments in external decommissioning trust funds, is considered available for sale and is carried at market value. Unrealized gains or losses resulting from changes in market values of these decommissioning investments are deferred as a regulatory liability or asset, respectively, due to the effects of regulation. NSP-Minnesota anticipates offsetting such unrealized gains or losses, when realized, against decommissioning costs in future ratemaking.

Regulatory Deferrals—As a regulated entity, NSP-Minnesota accounts for certain income and expense items using Statement of Financial Accounting Standards (SFAS) No. 71—Accounting for the Effects of Regulation. Under SFAS No. 71:

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

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

2. PREFERRED SECURITIES

In 1997, a wholly-owned special purpose subsidiary trust of NSP-Minnesota issued $200 million of 7.875 percent preferred securities that mature in 2037. Distributions paid by the subsidiary trust on the preferred securities are financed through interest payments on debentures issued by NSP-Minnesota and held by the subsidiary trust, which are eliminated in NSP-Minnesota's consolidation. The preferred securities are redeemable at $25 per share beginning in 2002. Distributions and redemption payments are guaranteed by NSP-Minnesota. Distributions paid to preferred security holders are reflected as a financing cost in the Income Statements along with interest expense.

3. COMMON STOCK

NSP-Minnesota's first mortgage indenture includes certain restrictions on paying cash dividends. Even with these restrictions, NSP-Minnesota could have paid more than $600 million in additional cash dividends in 1999.

4. SHORT-TERM BORROWINGS

Short-term debt outstanding at Dec. 31 consisted of:

(Millions of dollars)		1999			1998
Utility short-term debt		$	420		$	114
Weighted average interest rate—Dec. 31			5.9	%		5.3	%

At the end of 1998 and 1999, NSP-Minnesota had a $300 million revolving credit facility under a commitment fee arrangement. This facility provides short-term financing in the form of bank loans,

letters of credit and support for commercial paper sales. NSP-Minnesota did not borrow or issue any letters of credit against this facility in 1998 or 1999.

5. LONG-TERM DEBT

Except for minor exclusions, all property of NSP-Minnesota is subject to the lien of the first mortgage indenture, which is a contract between the company and its bond holders. A lien on the related property secures other debt securities.

The annual sinking-fund requirements of NSP-Minnesota's first mortgage indentures are the amounts necessary to redeem 1 percent of the highest principal amount of each series of first mortgage bonds at any time outstanding, excluding:

•: series issued for pollution control and resource recovery financings
•: certain other series totaling $900 million

NSP-Minnesota may apply property additions in lieu of cash for sinking fund requirements on all series, as permitted by their first mortgage indenture.

At Dec. 31, 1999, the interest rates on NSP-Minnesota's fixed-rate long-term debt ranged from 3.50 percent to 7.875 percent.

NSP-Minnesota's 2011 and 2019 series First Mortgage Bonds have variable interest rates, which currently change at various periods up to 270 days, based on prevailing rates for certain commercial paper securities or similar issues. The interest rates applicable to these issues averaged 5.75 percent and 3.7 percent, respectively, at Dec. 31, 1999. The 2011 series bonds are redeemable upon seven days notice at the option of the bondholder. NSP-Minnesota also is potentially liable for repayment of the 2019 series when the bonds are tendered, which occurs each time the variable interest rates change. The principal amount of all of these variable rate bonds outstanding, which totaled $141.6 million at Dec. 31, 1999, represents potential short-term obligations and, therefore, is reported under current liabilities on the Balance Sheets.

Maturities and sinking-fund requirements on long-term debt are:

2000	$114.1 million	2003	$215.0 million
2001	$157.7 million	2004	$8.1 million
2002	$7.9 million

6. INCOME TAXES

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

				1999			1998			1997
Federal statutory rate					35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
	State income taxes, net of federal income tax benefit				5.7	%		5.9	%		5.8	%
	Tax credits recognized				(3.5)	%		(2.7)	%		(2.8)	%
	Regulatory differences—utility plant items				2.2	%		1.3	%		1.1	%
	Other—net				(1.5)	%		(2.3)	%		(1.2)	%

Effective income tax rate					37.9	%		37.2	%		37.9	%

(Thousands of dollars)
Income taxes are comprised of the following expense (benefit) items:
	Related to utility operations:
		Current federal tax expense		$	91,543		$	112,980		$	108,102
		Current state tax expense			24,113			29,318			24,679
		Deferred federal tax expense			(7,951	)		(11,918	)		(6,885	)
		Deferred state tax expense			(1,022	)		(658	)		807
		Deferred investment tax credits			(8,269	)		(8,263	)		(8,167	)

		Total			98,414			121,459			118,536

	Related to nonregulated operations and nonoperating items:
		Current federal tax expense			(4,063	)		5,447			(187	)
		Current state tax expense			(1,077	)		(898	)		(421	)
		Current federal tax credits			(765	)		(705	)		(703	)
		Deferred federal tax expense			3,899			(409	)		3,614
		Deferred state tax expense			1,078			(126	)		980
		Deferred investment tax credits			(55	)		(55	)		(55	)

		Total			(983	)		3,254			3,228

			Total income tax expense	$	97,431		$	124,713		$	121,764

The components of NSP-Minnesota's net deferred tax liability (current and noncurrent portions) at Dec. 31 were:

(Thousands of dollars)		1999			1998
Deferred tax liabilities:
	Differences between book and tax bases of property	$	904,093		$	890,910
	Regulatory assets		75,672			92,116
	Tax benefit transfer leases		23,349			27,073
	Other		12,825			13,546

	Total deferred tax liabilities	$	1,015,939		$	1,023,645

Deferred tax assets:
	Differences between book and tax bases of property	$	180,140		$	171,798
	Regulatory liabilities		61,965			67,833
	Deferred compensation, vacation and other accrued liabilities not currently deductible		50,537			57,575
	Deferred investment tax credits		39,592			43,080
	Other		(1,320	)		(561	)

	Total deferred tax assets	$	330,914		$	339,725

	Net deferred tax liability	$	685,025		$	683,920

7. BENEFIT PLANS AND OTHER POSTRETIREMENT BENEFITS

NSP-Minnesota offers the following benefit plans to its benefit employees. Approximately 40 percent of NSP-Minnesota benefit employees are represented by four local labor unions under a collective-bargaining agreement, which expires in 2004.

Pension Benefits—NSP-Minnesota has two noncontributory, defined benefit pension plans that cover almost all utility employees. Benefits are based on a combination of years of service, the employee's average pay and Social Security benefits.

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

NSP-Minnesota's pension costs for the past three years were as follows:

Components of Net Periodic Benefit Cost (Thousands of dollars)	Pension Benefits
	1999			1998			1997
Service cost	$	29,771		$	26,239		$	22,932
Interest cost		73,331			67,450			62,265
Expected return on plan assets		(125,346	)		(110,683	)		(100,361	)
Amortization of transition (asset) obligation		(66	)		(66	)		(66	)
Amortization of prior service cost		17,742			5,556			904
Recognized actuarial (gain) or loss		(31,901	)		(24,041	)		(16,536	)

Net periodic benefit cost (credit) under SFAS 87		(36,469	)		(35,545	)		(30,862	)
Costs recognized due to effects of ratemaking		36,469			35,545			30,862

Net Periodic Benefit Cost Recognized for Financial Reporting	$	0		$	0		$	0

The funded status of the Former NSP pension plans for the last two years, including amounts allocable to NSP-Minnesota, was as follows:

	Total Former NSP Plan						NSP-Minnesota Portion
(Thousands of dollars)	1999			1998			1999			1998
Benefit Obligation at Jan. 1	$	1,143,464		$	1,048,251		$	980,194		$	898,600
Service cost		36,421			31,643			29,771			26,239
Interest cost		86,429			78,839			73,331			67,450
Plan amendments		184,255			102,315			154,678			84,979
Actuarial (gain) loss		(105,634	)		(41,635	)		(97,271	)		(33,099	)
Benefit payments		(97,086	)		(75,949	)		(81,761	)		(63,975	)

Benefit Obligation at Dec. 31	$	1,247,849		$	1,143,464		$	1,058,942		$	980,194

Fair value of plan assets at Jan. 1	$	2,221,819		$	1,978,538		$	1,904,576		$	1,720,743
Actual return on plan assets		293,904			319,230			229,673			247,808
Benefit payments		(97,086	)		(75,949	)		(81,761	)		(63,975	)

Fair Value of Plan Assets at Dec. 31	$	2,418,637		$	2,221,819		$	2,052,488		$	1,904,576

Funded status at Dec. 31—net asset (obligation)	$	1,170,788		$	1,078,355		$	993,546		$	924,382
Unrecognized transition (asset) obligation		(311	)		(387	)		(274	)		(340	)
Unrecognized prior service cost		277,350			114,305			232,354			95,418
Unrecognized net (gain) loss		(1,381,889	)		(1,167,340	)		(1,172,825	)		(1,003,128	)

Net Asset Recognized—Prepaid Pension Cost	$	65,938		$	24,933		$	52,801		$	16,332

Weighted average assumptions used in benefit calculations were:

	1999		1998
Discount rate at end of year	7.5	%	6.5	%
Expected return on plan assets for year—before tax	8.5	%	8.5	%
Rate of future compensation increase per year	4.5	%	4.0	%

Postretirement Health Care—NSP-Minnesota has a contributory health and welfare benefit plan that provides health care and death benefits to almost all NSP-Minnesota retirees. The plan was terminated for nonbargaining employees retiring after 1998 and for bargaining employees after 1999. For covered retirees, the plan enables NSP-Minnesota and such retirees to share the costs of retiree health care. NSP-Minnesota nonbargaining retirees pay 40 percent of total health care costs. Cost-sharing for bargaining employees is governed by the terms of NSP-Minnesota's collective bargaining agreement.

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

Regulators for almost all of NSP-Minnesota's retail and wholesale customers have allowed full rate recovery of increased benefit costs under SFAS No. 106. Minnesota retail regulators require external funding to the extent it is tax advantaged. Such funding began for Minnesota in 1998. For wholesale ratemaking, FERC requires external funding for all benefits paid and accrued under SFAS No. 106. Plan assets held in external funding trusts principally consist of investments in equity mutual funds and cash equivalents.

NSP-Minnesota's postretirement health care costs for the past three years were as follows:

	Other Postretirement Benefits
Components of Net Periodic Benefit Cost (Thousands of dollars)	Other Postretirement Benefits
	1999			1998			1997
Service cost	$	156		$	2,628		$	4,145
Interest cost		7,583			13,180			15,759
Expected return on plan assets		(1,526	)		(667	)		(522	)
Amortization of transition (asset) obligation		2,052			7,079			9,236

Net Periodic Benefit Cost Recognized for Financial Reporting	$	8,265		$	22,220		$	28,618

The funded status of the Former NSP postretirement health care plan for the past two years, including amounts allocable to NSP-Minnesota, is as follows:

	Total Former NSP Plan						NSP-Minnesota Portion
(Thousands of dollars)	1999			1998			1999			1998
Benefit Obligation at Jan. 1	$	219,762		$	279,230		$	181,740		$	232,824
Service cost		196			3,247			156			2,628
Interest cost		9,184			15,896			7,583			13,180
Plan amendments		(80,840	)		(51,456	)		(66,761	)		(43,140	)
Actuarial (gain) loss		8,269			(9,732	)		6,375			(8,878	)
Benefit payments		(16,637	)		(17,423	)		(14,745	)		(14,874	)

Benefit Obligation at Dec. 31	$	139,934		$	219,762		$	114,348		$	181,740

Fair value of plan assets at Jan. 1	$	34,514		$	19,783		$	21,331		$	8,337
Actual return on plan assets		3,982			2,471			2,213			998
Employer contributions		13,339			29,683			11,528			26,870
Benefit payments		(16,637	)		(17,423	)		(14,745	)		(14,874	)

Fair Value of Plan Assets at Dec. 31	$	35,198		$	34,514		$	20,327		$	21,331

Funded status at Dec. 31—net obligation	$	104,736		$	185,248		$	94,021		$	160,409
Unrecognized transition obligation		(22,073	)		(104,482	)		(19,493	)		(88,306	)
Unrecognized prior service cost		2,926			2,399
Unrecognized net gain (loss)		(10,580	)		(3,790	)		(7,154	)		(1,466	)

Net Amount Recognized—Accrued Liability	$	75,009		$	79,375		$	67,374		$	70,637

		1999			1998
Weighted average assumptions used in benefit calculations were:
Discount rate at end of year			7.5	%	6.5	%
Expected return on plan assets for year—before tax			8.0	%	8.0	%
Rate of future health care cost increase per year:
	Next succeeding year—age 65 and older		6.1	%	6.1	%
	Next succeeding year—under age 65		8.1	%	8.1	%
	Final rate of increase in 2004		5.5	%	5.0	%
Effect of changes in the assumed health care cost trend rate for each year on NSP-Minnesota's portion:
	1% increase in APBO components at Dec. 31, 1999	$	9,960
	1% decrease in APBO components at Dec. 31, 1999		(8,633	)
	1% increase in service and interest costs components of the net periodic cost		618
	1% decrease in service and interest costs components of the net periodic cost		(533	)

401(k)—NSP-Minnesota has a contributory, defined contribution Retirement Savings Plan, which complies with section 401(k) of the Internal Revenue Code and covers substantially all utility employees. NSP-Minnesota matches specified amounts of employee contributions to the plan. NSP-Minnesota's matching contributions were approximately $5.7 million in 1999 and $3.8 million in 1998.

ESOP—NSP-Minnesota has a leveraged Employee Stock Ownership Plan (ESOP) that covers substantially all utility employees. NSP-Minnesota makes contributions to this noncontributory, defined contribution plan to the extent we realize a tax savings from dividends paid on certain ESOP shares. The ESOP holds shares of Former NSP common stock. Contributions to the ESOP, which represent compensation expense, were $4.2 million in 1999, $4.3 million in 1998 and $4.4 million in 1997.

ESOP contributions have no material effect on NSP-Minnesota earnings because the contributions are essentially offset by the tax savings provided by the dividends paid on ESOP shares. NSP-Minnesota allocates leveraged ESOP shares to participants when it repays ESOP loans with dividends on stock held by the ESOP.

NSP-Minnesota's ESOP held 11.3 million shares of Former NSP common stock at the end of 1999 and 1998.

8. FINANCIAL INSTRUMENTS

Fair Values—The estimated Dec. 31 fair values of NSP-Minnesota's recorded financial instruments are as follows:

	1999				1998
(Thousands of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash, cash equivalents and short-term investments	$	11,344	$	11,344	$	20,125	$	20,125
Long-term investments	$	517,129	$	517,129	$	438,981	$	438,981
Long-term debt, including current portion	$	1,442,304	$	1,379,606	$	1,403,851	$	1,461,223

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

Derivatives—NSP-Minnesota's Energy Marketing division uses energy futures contracts, along with physical supply, to hedge market risk in the energy market. At Dec. 31, 1999, the notional amount of energy futures contracts was approximately $2 million. Management believes that the risk of counterparty nonperformance with regard to any of Energy Marketing's hedge transactions is not significant.

NSP-Minnesota's Energy Marketing division has exposure to the risk of changes in market prices of electricity and natural gas. As of Dec. 31, 1999, a 10 percent increase or decrease in electricity futures and forward prices would have an immaterial impact on NSP-Minnesota's financial results. Any changes in the values of these futures contracts would be offset by a change in the underlying commodities being hedged.

Letters of Credit—NSP-Minnesota uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations

At Dec. 31, 1999, NSP-Minnesota had $23 million in letters of credit outstanding. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

9. RELATED PARTY TRANSACTIONS

Interchange Agreement—The electric production and transmission costs of the entire NSP system are shared by NSP-Minnesota and NSP-Wisconsin, a wholly-owned subsidiary of Xcel Energy. A FERC approved agreement (Interchange Agreement) between the two companies provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs. Billings under the Interchange Agreement which are included in the Statements of Income are as follows (in thousands of dollars):

			1999		1998		1997
Operating revenues:
Electric
		Production related	$	192,069	$	190,282	$	180,635
		Transmission		15,366		15,963		13,652
	Gas			192		213		231
Operating expenses:
		Purchased and interchange power		48,193		48,165		47,588
		Gas purchased for resale		0		45		45
		Other operations		26,021		25,529		23,673

Gas Costs—One of Xcel's subsidiaries, Viking Gas Transmission Company (Viking), transports gas purchased by NSP-Minnesota from various suppliers. Under various contracts and agreements with Viking, which extend through 2008, NSP-Minnesota incurred transportation costs of $3.8 million in 1999, $3.4 million in 1998 and $3.5 million in 1997 for gas purchased through Viking, which is an affiliate company to NSP-Minnesota.

Affiliate Companies Accounts Receivable and Accounts Payable—Through 1999, all of the corporate and administrative services resided in Former NSP with amounts allocated to former NSP subsidiaries, as appropriate. Although future cost allocations will be from Xcel Services, and the associated accounts receivable will be with Xcel Services, for 1999 and 1998 the accounts receivable for these services was with NSP-Minnesota. In addition, there is an accounts receivable from NSP-Wisconsin for the interchange agreement described previously and notes receivable from NSP-Wisconsin for the short-term borrowing described below. Also, there is a note receivable (long-term and current portion), and related interest receivable from NRG Energy, an affiliate company related to the sale of Refuse- Derived Fuel assets to NRG in a previous year. The affiliate companies accounts receivable primarily represents all of these items. The affiliate companies accounts payable primarily represents income taxes payable to affiliates, since the Former NSP handled all income tax payables for its subsidiaries. In the future, Xcel Energy will handle this function and the associated payable or receivable will be with Xcel Energy and the various subsidiaries. In addition, in the future, NSP-Minnesota will have either an accounts payable or receivable to (or from) Xcel Energy for income taxes. The long-term notes receivable is included in Other Investments and Receivables on the Balance Sheets and is $5.8 million and $6.5 million at Dec. 31, 1999 and 1998, respectively. The accounts

payable to affiliates is included in Accounts Payable on the Balance Sheets and is $12.2 and $11.2 million at Dec. 31, 1999 and 1998, respectively.

Interest Costs and Income—NSP-Wisconsin obtains short-term borrowings from NSP-Minnesota at NSP-Minnesota's average daily interest rate, including the cost of NSP-Minnesota's compensating balance requirements. Other Interest and Amortization Expense and Nonoperating Income includes $2.5 million, $2.0 million and $1.4 million for 1999, 1998 and 1997, respectively, related to this. Short-Term Debt and Receivables from Affiliated Companies includes $80.8 million and $55.9 million, at Dec. 31, 1999 and 1998, respectively for these short-term borrowings.

10. REGULATORY ASSETS AND LIABILITIES

The following summarizes the individual components of unamortized regulatory assets and liabilities shown on the Balance Sheets at Dec. 31:

(Thousands of dollars)		Remaining Amortization Period	1999		1998
AFC recorded in plant(a)		Plant Lives	$	104,958		113,985
Conservation programs(a)		3 Years		0		65,963
Losses on reacquired debt		Term of Related Debt		41,450		44,355
Environmental costs		Primarily 10 Years		37,548		39,790
Unrecovered gas costs		1-2 Years		14,956		15,683
State commission accounting adjustments(a)		Plant Lives		5,247		5,141
Other		Various		4,017		3,562

	Total regulatory assets		$	208,176	$	288,479

Deferred income tax adjustments			$	70,916	$	70,605
Investment tax credit deferrals				66,698		72,733
Unrealized gains from decommissioning investments				177,578		138,613
Pension costs—regulatory differences				84,198		53,012
Conservation incentives				25,284
Fuel costs, refunds and other				15,043		15,202

	Total regulatory liabilities		$	439,717	$	350,165

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

11. JOINT PLANT OWNERSHIP

NSP-Minnesota is part owner of an 860-megawatt coal-fired electric generating unit called Sherco 3. NSP-Minnesota owns, and has financed, 59 percent and Southern Minnesota Municipal Power Agency owns, and has financed, 41 percent of Sherco 3. NSP-Minnesota is the operating agent under the joint ownership agreement. NSP-Minnesota's share of related expenses for Sherco 3 is included in Utility Operating Expenses. NSP-Minnesota's share of the gross cost recorded in Utility Plant was approximately $607 million at year-end 1999 and $604 million at year-end 1998. The accumulated provisions for depreciation were $233 million in 1999 and $215 million in 1998.

12. NUCLEAR OBLIGATIONS

Fuel Disposal—NSP-Minnesota is responsible for temporarily storing used—or spent—nuclear fuel from its nuclear plants. The U.S. Department of Energy (DOE) is responsible for permanently storing spent fuel from NSP-Minnesota's nuclear plants as well as from other U.S. nuclear plants. NSP-Minnesota has been funding its portion of the DOE's permanent disposal program since 1981. The fuel disposal fees are based on a charge of 0.1 cent per kilowatt-hour sold to customers from nuclear generation. Fuel expense includes DOE fuel disposal assessments of approximately $12 million in 1999, $11 million in 1998 and $10 million in 1997.

In total, NSP-Minnesota had paid approximately $272 million to the DOE through Dec. 31, 1999. However, we cannot determine whether the amount and method of the DOE's assessments to all utilities will be sufficient to fully fund the DOE's permanent storage or disposal facility.

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

Without a DOE facility, NSP-Minnesota has been providing, with regulatory and legislative approval, its own temporary on-site storage facilities at its Monticello and Prairie Island nuclear plants. With the dry cask storage facilities approved in 1994, NSP-Minnesota believes it has adequate storage capacity to continue operation of its Prairie Island nuclear plant until at least 2007. The Monticello nuclear plant has storage capacity to continue operations until 2010. Storage availability to permit operation beyond these dates is not assured at this time. NSP-Minnesota is investigating all of its alternatives for spent fuel storage until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent nuclear fuel as part of a consortium of electric utilities. If on-site temporary storage at Prairie Island reaches approved capacity, NSP-Minnesota could seek interim storage at this or another contracted private facility, if available.

Nuclear fuel expense includes payments to the DOE for the decommissioning and decontamination of the DOE's uranium enrichment facilities. In 1993, NSP-Minnesota recorded the DOE's initial assessment of $46 million, which is payable in annual installments from 1993-2008. NSP-Minnesota is amortizing each installment to expense on a monthly basis in the 12 months following each payment. The most recent installment paid in 1999 was $4 million; future installments are subject to inflation adjustments under DOE rules. NSP-Minnesota is obtaining rate recovery of these DOE assessments through the cost-of-energy adjustment clause as the assessments are amortized. Accordingly, we deferred the unamortized assessment of $32 million at Dec. 31, 1999, as a regulatory asset.

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

The Financial Accounting Standards Board (FASB) has proposed new accounting standards, which, if approved, would require the full accrual of nuclear plant decommissioning and other site exit

obligations no sooner than 2002. Using Dec. 31, 1999, estimates, NSP-Minnesota's adoption of the proposed accounting would result in the recording of the total discounted decommissioning obligation of $705 million as a liability, with the corresponding costs capitalized as plant and other assets and depreciated over the operating life of the plant. NSP-Minnesota has not yet determined the potential impact of the FASB's proposed changes in the accounting for site exit obligations, such as costs of removal, other than nuclear decommissioning. However, the ultimate decommissioning and site exit costs to be accrued are expected to be similar to the current methodology. The effects of regulation are expected to minimize or eliminate any impact on operating expenses and results of operations from this future accounting change.

Consistent with cost recovery in utility customer rates, NSP-Minnesota records annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Since the costs are expected to be paid in 2010-2022, funding presumes that current costs will escalate in the future at a rate of 4.5 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant recovery period. This annuity approach uses an assumed rate of return on funding, which is currently 6 percent, net of tax, for external funding and approximately 8 percent, net of tax, for internal funding.

The MPUC last approved NSP-Minnesota's nuclear decommissioning study and related nuclear plant depreciation capital recovery request in April 1997, using 1993 cost data. Although NSP-Minnesota expects to operate Prairie Island through the end of each unit's licensed life, the approved capital recovery would allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs, in 2008. This is about six years earlier than each unit's licensed life. The approved recovery period for Prairie Island has been reduced because of the uncertainty regarding used fuel storage. NSP-Minnesota believes future decommissioning cost accruals will continue to be recovered in customer rates.

The total obligation for decommissioning currently is expected to be funded approximately 82 percent by external funds and 18 percent by internal funds, as approved by the MPUC. Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. Costs not funded by external trust assets, including accumulated earnings, will be funded through internally generated funds and issuance of NSP-Minnesota debt or stock. The assets held in trusts as of Dec. 31, 1999, primarily consisted of investments in fixed income securities, such as tax-exempt municipal bonds and U.S. government securities that mature in two to 30 years, and common stock of public companies. NSP-Minnesota plans to reinvest matured securities until decommissioning begins.

At Dec. 31, 1999, NSP-Minnesota had recorded and recovered in rates cumulative decommissioning accruals of $549 million. The following table summarizes the funded status of NSP-Minnesota's decommissioning obligation at Dec. 31, 1999:

(Thousands of dollars)	1999
Estimated decommissioning cost obligation from most recently approved study (1993 dollars)	$	750,824
Effect of escalating costs to 1999 dollars (at 4.5 percent per year)		226,944

Estimated decommissioning cost obligation in current dollars		977,768
Effect of escalating costs to payment date (at 4.5 percent per year)		867,017

Estimated future decommissioning costs (undiscounted)		1,844,785
Effect of discounting obligation (using risk-free interest rate)		(1,140,003	)

Discounted decommissioning cost obligation		704,782
Assets held in external decommissioning trust		517,129

Discounted decommissioning obligation in excess of assets currently held in external trust	$	187,653

Decommissioning expenses recognized include the following components:

(Thousands of dollars)		1999			1998			1997
Annual decommissioning cost accrual reported as depreciation expense:
	Externally funded	$	33,178		$	33,178		$	33,178
	Internally funded (including interest costs)		1,595			1,477			1,368
Interest cost on externally funded decommissioning obligation			4,191			6,960			7,690
Earnings from external trust funds			(4,191	)		(6,960	)		(7,690	)

Net decommissioning accruals recorded		$	34,773		$	34,655		$	34,546

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

Every three years a nuclear plant decommissioning filing is made with the MPUC. The last filing was made with the MPUC in October 1999 and will be effective for cost accruals Jan. 1, 2000.

13. COMMITMENTS AND CONTINGENT LIABILITIES

Capital Commitments—NSP-Minnesota estimates utility capital expenditures, including purchases of nuclear fuel, will be $400 million in 2000 and $1.9 billion for 2000-2004. There also are contractual commitments for the disposal of spent nuclear fuel. For more information see Note 12.

Legislative Resource Commitments—In 1994, NSP-Minnesota received Minnesota legislative approval for additional on-site temporary spent fuel storage facilities at NSP-Minnesota's Prairie Island plant, provided NSP-Minnesota satisfies certain requirements. Seventeen dry cask containers were approved. As of Dec. 31, 1999, NSP-Minnesota had loaded nine casks. The Minnesota Legislature established several energy resource and other commitments for NSP-Minnesota to obtain the Prairie

Island temporary nuclear fuel storage facility approval. These commitments can be met by building, purchasing or, in the case of biomass, converting generation resources.

The 1994 legislation requires NSP-Minnesota to have 425 megawatts of wind resources contracted by Dec. 31, 2002. Of this commitment, approximately 130 megawatts remain to be contracted. During 1999, the MPUC ordered an additional 400 megawatts to be contracted by 2012, subject to the lowest-cost alternative determinations.

The 1994 legislation also requires NSP-Minnesota to contract for 125 megawatts of biomass-fueled energy, which has essentially been fulfilled.

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

Guarantees—NSP-Minnesota has sold a portion of its other receivables to a third party. The portion of the receivables sold consisted of customer loans to local and state government entities for energy efficiency improvements under various conservation programs offered by NSP-Minnesota. Under the sales agreements, NSP-Minnesota is required to guarantee repayment to the third party of the remaining loan balances. At Dec. 31, 1999, the outstanding balance of the loans was approximately $25 million. Based on prior collection experience of these loans, NSP-Minnesota believes that losses under the loan guarantees, if any, would have an immaterial impact on the results of operations.

Leases—Rentals under operating leases for NSP-Minnesota were approximately $33 million, $30 million and $28 million for 1999, 1998 and 1997, respectively. Future commitments under these leases generally decline from current levels.

Fuel Contracts—NSP-Minnesota has contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2000 and 2013. In total, NSP-Minnesota is committed to the minimum purchase of approximately $399 million of coal, $21 million of nuclear fuel and $143 million of natural gas and related transportation, or to make payments in lieu thereof, under these contracts. In addition, NSP-Minnesota is required to pay additional amounts depending on actual quantities shipped under these agreements.

NSP-Minnesota has developed a mix of natural gas supply, transportation and storage contracts designed to meet its needs for retail gas sales. The contracts are with several suppliers and for various periods of time. Because NSP-Minnesota has other sources of fuel available and suppliers are expected to continue to provide reliable fuel supplies, risk of loss from nonperformance under all fuel contracts is not considered significant. In addition, NSP-Minnesota's risk of loss, in the form of increased costs, from market price changes in fuel is mitigated through the cost-of-energy adjustment provision of the ratemaking process, which provides for recovery of nearly all fuel costs.

Power Agreements—NSP-Minnesota has several agreements to purchase electricity from the Manitoba Hydro-Electric Board (MH). A summary of the agreements is as follows:

Power Agreements		Years	Mw
Participation power purchase		2000 - 2005	500
Seasonal diversity exchanges:
	Summer exchanges from MH	2000 - 2014	150
		2000 - 2016	200
	Winter exchanges to MH	2000 - 2014	150
		2000 - 2015	200
		2015 - 2017	400
		2018	200

The cost of the 500-megawatt participation power purchase commitment is based on 80 percent of the costs of owning and operating NSP-Minnesota's Sherco 3 generating plant, adjusted to 1993 dollars. The future annual capacity costs for the 500-megawatt MH agreement are estimated to be approximately $58 million. There are no capacity payments for the diversity exchanges. These commitments represent about 17 percent of MH's system capacity and account for approximately 10 percent of NSP's 2000 electric system capability. The risk of loss from nonperformance by MH is not considered significant, and the risk of loss from market price changes is mitigated through cost-of-energy rate adjustments.

NSP-Minnesota has an agreement with Minnkota Power Cooperative for the purchase of summer season capacity and energy. NSP-Minnesota will buy 150 megawatts of summer season capacity for approximately $12 million annually in 2000 and 2001. From 2002-2015, NSP-Minnesota will purchase 100 megawatts of capacity for $10 million annually. NSP-Minnesota also has a summer purchase power agreement with Minnesota Power for the purchase of 173 megawatts, including reserves, for 2000. The annual cost of this capacity will be approximately $2 million.

NSP-Minnesota has agreements with several nonregulated power producers to purchase electric capacity and associated energy. The cost of these commitments is approximately $45 million annually for 379 megawatts of summer capacity for 2000-2003. These commitments are expected to range between $52 million and $84 million annually for 2004-2024. These commitments are expected to decline to approximately $27 million annually for 2025-2027, due to the expiration of existing agreements.

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

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Limited (NEIL). The coverage limits are $1.5 billion for each of NSP-Minnesota's two nuclear plant sites.

NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $4 million for business interruption insurance and $15 million for property damage insurance if losses exceed accumulated reserve funds.

Environmental Contingencies—Other long-term liabilities include an accrual of $25 million, and other current liabilities include an accrual of $6 million, at Dec. 31, 1999, for estimated costs associated with environmental remediation. Approximately $24 million of the long-term liability and $4 million of the current liability relate to a DOE assessment for decommissioning a federal uranium enrichment facility. Other estimates have been recorded for expected environmental costs associated with manufactured gas plant sites formerly used by NSP-Minnesota, and other waste disposal sites, as discussed later. These environmental liabilities do not include accruals recorded and collected from customers in rates for future nuclear fuel disposal costs or decommissioning costs related to NSP-Minnesota's nuclear generating plants. See Note 12 for further discussion of nuclear items.

The Environmental Protection Agency (EPA) or state environmental agencies have designated NSP-Minnesota as a potentially responsible party (PRP) for 14 waste disposal sites to which NSP-Minnesota allegedly sent hazardous materials.

•: Eleven of these 14 sites have been remediated and, consistent with settlements reached with the EPA and other PRPs, NSP-Minnesota has paid $2.4 million for its share of the remediation costs. One site that was previously remediated was reactivated due to a change in the use of the land. While these remediated sites will continue to be monitored, NSP-Minnesota expects that future remediation costs, if any, will be immaterial. Under applicable law, NSP-Minnesota, along with each PRP, could be held jointly and severally liable for the total remediation costs of PRP sites.
•: Neither the total remediation cost nor the final method of cost allocation among all PRPs of the three unremediated sites has been determined. However, NSP-Minnesota has recorded an estimate of approximately $0.1 million for its share of future costs for these sites. NSP-Minnesota is not aware of the other parties' inability to pay, nor does it know if responsibility for any of the sites is in dispute.

While it is not feasible to determine the ultimate impact of PRP site remediation at this time, the amounts accrued represent the best current estimate of NSP-Minnesota's future liability. It is NSP-Minnesota's practice to vigorously pursue and, if necessary, litigate with insurers to recover incurred remediation costs whenever possible. Through litigation, NSP-Minnesota has recovered a portion of the remediation costs paid to date. Management believes remediation costs incurred, but not recovered, from insurance carriers or other parties should be allowed recovery in future ratemaking. Until NSP-

Minnesota is identified as a PRP, it is not possible to predict the timing or amount of any costs associated with sites, other than those discussed previously.

NSP-Minnesota is also investigating other properties that were formerly sites of gas manufacturing, gas storage plants or gas pipelines to determine if waste materials are present and if they are an environmental or health risk. NSP-Minnesota also determines if it has any responsibility for remedial action and if recovery under NSP-Minnesota's insurance policies can contribute to any remediation costs.

•: NSP-Minnesota has remediated four sites, which continue to be monitored. NSP-Minnesota has paid $7.3 million to remediate these sites and expects to incur only immaterial monitoring costs related to these sites.
•: Another 11 gas sites remain under investigation. NSP-Minnesota is taking remedial action at four of these sites.
•: As of Dec. 31, 1999, NSP-Minnesota had paid $4.3 million for the four active sites and had recorded an estimated liability of approximately $2.6 million for future costs at these sites, with payment expected over the next five years. This estimate is based on prior experience and includes investigation, remediation and litigation costs.
•: No liability has been recorded for remediation or investigation of the remaining seven sites under investigation because the present land use at each of these sites does not warrant a response action.

While it is not feasible to determine at this time the ultimate cost of gas site remediation, the amounts accrued represent the best current estimate of NSP-Minnesota's future liability for any required cleanup or remedial actions at these former gas operating sites. Environmental remediation costs may be recovered from insurance carriers, third parties or in future rates. The MPUC allowed NSP-Minnesota to defer certain remediation costs of four active sites in 1994. In September 1998, the MPUC allowed the recovery of these gas site remediation costs in gas rates, with a portion assigned to NSP-Minnesota's electric operations for two sites formerly used by NSP-Minnesota generating facilities. Accordingly, NSP-Minnesota has recorded an environmental regulatory asset for these costs. NSP-Minnesota may request recovery of costs to remediate other activated sites following the completion of preliminary investigations.

The Clean Air Act calls for phased-in reductions in emissions of sulfur dioxide and nitrogen oxides from electric generating plants. NSP-Minnesota has invested significantly over the years to reduce sulfur dioxide emissions at its plants. No additional capital expenditures are anticipated to comply with the sulfur dioxide emission limits of the Clean Air Act. NSP-Minnesota is completing installation of over-fire air at the King plant to meet the NO_X emission limitations. NSP-Minnesota's capital expenditures include some costs for ensuring compliance with the Clean Air Act; other expenditures may be necessary upon EPA finalization of remaining rules. Because NSP-Minnesota is still in the process of implementing some provisions of the Clean Air Act, its total financial impact is unknown at this time. Capital expenditures for opacity compliance are included in the capital expenditure commitments disclosed previously. The depreciation of these capital costs will be subject to regulatory recovery in future rate proceedings.

Environmental liabilities are subject to considerable uncertainties that affect NSP-Minnesota's ability to estimate its share of the ultimate costs of remediation and pollution control efforts. Uncertainties include the nature and extent of site contamination, the extent of required cleanup efforts, varying costs of alternative cleanup methods and pollution control technologies, changes in environmental remediation and pollution control requirements, the potential effect of technological improvements, the number and financial strength of other potentially responsible parties at multi-party sites and the identification of new environmental cleanup sites. NSP-Minnesota has recorded and/or disclosed its best estimate of expected future environmental costs and obligations.

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

On Dec. 11, 1998, a gas explosion in St. Cloud, Minn., killed four people, including two NSP-Minnesota employees, injured approximately 14 people and damaged several buildings. The accident occurred as a crew from Cable Constructors Inc. (CCI) was installing fiber optic cable for Seren Innovations, a subsidiary of Xcel Energy and an affiliate company to NSP-Minnesota. Seren, CCI and Sirti, an architecture/engineering firm retained by Seren, are named as defendants in 12 lawsuits relating to the explosion. NSP-Minnesota is a defendant in eight of the lawsuits. NSP-Minnesota and Seren deny any liability for this accident. NSP-Minnesota has a self-insured retention deductible of $2 million with general liability coverage limits of $185 million. Seren's primary insurance coverage is $1 million and its secondary insurance coverage is $185 million. The ultimate cost to NSP-Minnesota and Seren, if any, is presently unknown.

In April 1997, a fire damaged several buildings in downtown Grand Forks, N. D., during a flood in the city. On July 23, 1998, the St. Paul Mercury Insurance Co. commenced a lawsuit against NSP-Minnesota for damages in excess of $15 million. The suit was filed in the District Court in Grand Forks County in North Dakota. The insurance company alleges the fire was electrical in origin and that NSP-Minnesota was legally responsible for the fire because it failed to shut off electrical power to downtown Grand Forks during the flood and prior to the fire. Seven additional lawsuits were filed against NSP- Minnesota by insurance companies which insured businesses damaged by the fire. One additional lawsuit filed by the First National Bank of Grand Forks is venued in Federal Court. The total of damages being sought by all these lawsuits is in excess of $30 million. NSP-Minnesota denied any liability, asserting that it was not legally responsible for this unforeseeable event. NSP-Minnesota has a self-insured retention deductible of $2 million, with general liability insurance coverage limits of $150 million. The ultimate cost to NSP-Minnesota, if any, is unknown at this time.

14. SEGMENT AND RELATED INFORMATION

NSP-Minnesota has two reportable segments: Electric Utility and Gas Utility.

•: NSP-Minnesota's Electric Utility generates, transmits and distributes electricity primarily in Minnesota, North Dakota and South Dakota. It also makes sales for resale and provides wholesale transmission service to various entities in the United States.
•: NSP-Minnesota's Gas Utility transports, stores and distributes natural gas and propane primarily in Minnesota and North Dakota.

NSP-Minnesota reports net income and earnings per share for its electric and gas segments on a basis consistent with consolidated net income and earnings per share, except that allocations are needed for some items, as described later. Intercompany and intersegment sales are priced at approved tariff rates and are immaterial. Assets by segment are not reported to management and are not included in the disclosures that follow.

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

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

The "all other" category includes segments that measure below the quantitative threshold for separate disclosure and consists primarily of small nonregulated companies.

Business Segments

1999
1999	Electric Utility						Reconciling Eliminations	Consolidated Total(a)
(Thousands of dollars)	Electric Utility		Gas Utility		All Other		Reconciling Eliminations	Consolidated Total(a)
Operating revenues from external customers(b)	$	2,266,521	$	364,340	$	24,926		$	2,655,787
Intersegment revenues		692		1,495					2,187

Total revenues	$	2,267,213	$	365,835	$	24,926		$	2,657,974

Depreciation and amortization		286,894		23,235		2,512			312,641
Interest income		4,305		513		259			5,077
Financing costs, mainly interest expense		106,815		12,721		1,238			120,774
Income tax expense (credit)		93,866		2,285		1,280			97,431
Segment net income (loss)	$	145,906	$	11,200	$	1,874		$	158,980

1998
1998		Electric Utility						Reconciling Eliminations	Consolidated Total(a)
(Thousands of dollars)		Electric Utility		Gas Utility		All Other		Reconciling Eliminations	Consolidated Total(a)
Operating revenues from external customers(b)		$	2,243,125	$	355,847	$	25,124		$	2,624,096
Intersegment revenues			648		4,721					5,369

	Total revenues	$	2,243,773	$	360,568	$	25,124		$	2,629,465

Depreciation and amortization			274,953		21,106		2,468			298,527
Interest income			10,646		1,255		205			12,106
Financing costs, mainly interest expense			93,878		11,071		1,423			106,372
Income tax expense (credit)			117,044		6,578		1,091			124,713
Segment net income (loss)		$	196,258	$	12,259	$	1,689		$	210,206

1997
1997	Electric Utility						Reconciling Eliminations	Consolidated Total(a)
(Thousands of dollars)	Electric Utility		Gas Utility		All Other		Reconciling Eliminations	Consolidated Total(a)
Operating revenues from external customers(b)	$	2,100,409	$	410,977	$	24,301		$	2,535,687
Intersegment revenues		831		3,882					4,713

Total revenues	$	2,101,240	$	414,859	$	24,301		$	2,540,400

Depreciation and amortization		266,816		19,679		2,402			288,897
Interest income		2,510		261		239			3,010
Financing costs, mainly interest expense		96,641		10,063		1,543			108,247
Income tax expense (credit)		113,009		7,684		1,071			121,764
Segment net income (loss)	$	181,658	$	16,221	$	1,586		$	199,465

(a): The Consolidated Total amounts for income and expense items represent the sum of utility amounts and nonoperating amounts from the Statements of Income. The depreciation and amortization amounts in the Statements of Cash Flows are different than reported in the Consolidated Total column due to classification of certain depreciation and amortization amounts as other expense items in the Income Statement.
(b): All operating revenues are from external customers located in the United States.

15. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)

	Quarter Ended
(Thousands of dollars)	March 31, 1999		June 30, 1999(a)		Sept. 30,1999		Dec. 31, 1999(a)
Utility operating revenues	$	666,458	$	584,084	$	767,244	$	615,262
Utility operating income		92,032		38,366		160,911		86,946
Net income		41,471		6,663		79,250		31,596

	Quarter Ended
(Thousands of dollars)	March 31, 1998		June 30, 1998		Sept. 30,1998		Dec. 31, 1998
Utility operating revenues	$	636,116	$	601,319	$	720,690	$	646,216
Utility operating income		84,204		74,510		179,876		87,980
Net income		40,919		27,016		98,571		43,700

(a): 1999 results include two adjustments related to regulatory recovery of conservation program incentives. Second quarter results were reduced by $35 million before taxes due to the disallowance of 1998 incentives. Fourth quarter results were reduced by $22 million before taxes due to the reversal of all income recorded through the third quarter for 1999 electric conservation program incentives.

Item 14—Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

In connection with the merger, Xcel Energy's management informed PricewaterhouseCoopers LLP that the firm would no longer be engaged as principal independent accountants for Xcel Energy and NSP-Minnesota. On August 18, 2000, the Audit Committee of Xcel Energy's Board of Directors recommended, and the Xcel Energy Board approved, the decision to change principal independent accountants for the Xcel Energy and NSP-Minnesota for 2000. PricewaterhouseCoopers LLP will be retained as independent accountants for certain of Xcel Energy's non-utility subsidiaries, including NRG Energy, Inc. (also a public registrant).

PricewaterhouseCoopers LLP's reports on NSP-Minnesota's financial statements for the two most recent fiscal years ended December 31, 1998 and 1999 contained no adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principle.

In connection with its audits for the two most recent fiscal years and through August 18, 2000, there have been no disagreements with PricewaterhouseCoopers LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements if not resolved to the satisfaction of PricewaterhouseCoopers LLP would have caused them to make reference thereto in their report on the financial statements for such years.

During the two most recent fiscal years and through August 18, 2000, there have been no reportable events (as defined in Commission Regulation S-K Item 304 (a)(1)(v)).

Xcel Energy has requested that PricewaterhouseCoopers LLP furnish it with a letter addressed to the Commission stating whether or not it agrees with the above statements. PricewaterhouseCoopers LLP's letter dated August 18, 2000, is filed as Exhibit 16.01 to this Form 10.

Xcel Energy and NSP-Minnesota have engaged Arthur Andersen LLP as their new principal independent accountants as of August 18, 2000.

Item 15—Financial Statements and Exhibits

(a)

Financial Statements. The following financial statements are filed herewith as part of Item 13:

•: Consolidated Statements of Income for the Years Ended December 31, 1999, 1998 and 1997;
•: Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997;
•: Consolidated Statements Balance Sheets as of December 31, 1999 and 1998;
•: Consolidated Statements of Common Stockholder's Equity for the Years Ended December 31, 1999 and 1998;
•: Consolidated Statements of Capitalization for the Years Ended December 31, 1999,1998 and 1997;
•: Notes to Financial Statements; and
•: Summarized Quarterly Financial Data (Unaudited) (See Note 15 to Financial Statements).

Consolidated Financial Statements for the Nine Months Ended September 30, 2000 are filed as Exhibit 99.01 hereto.

(b): Exhibits.

Exhibits
	*	Indicates incorporation by reference.
	**	Indicates previously filed.
2.01	*	Agreement and Plan of Merger, dated as of March 24, 1999, by and between Northern States Power Company and New Century Energies, Inc. (Incorporated by reference to Exhibit 2.1 to the Report on Form 8-K (File No. 1-12907) of New Century Energies, Inc. dated March 24, 1999.)
3.01	**	Articles of Incorporation and Amendments of the Company.
3.02	**	By-Laws of the Company.
4.01	*	Trust Indenture, dated Feb. 1, 1937, from NSP to Harris Trust and Savings Bank, as Trustee. (Exhibit B-7 to File No. 2-5290.)
4.02	*	Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP to Harris Trust and Savings Bank, as Trustee. (Exhibit 4.02 to Form 10-K of NSP for the year 1988, File No. 1-3034.)
		Supplemental Indenture between NSP and said Trustee, supplemental to Exhibit 4.01, dated as follows:
4.03	*	June 1, 1942 (Exhibit B-8 to File No. 2-97667).
4.04	*	Feb. 1, 1944 (Exhibit B-9 to File No. 2-5290).
4.05	*	Oct. 1, 1945 (Exhibit 7.09 to File No. 2-5924).
4.06	*	July 1, 1948 (Exhibit 7.05 to File No. 2-7549).
4.07	*	Aug. 1, 1949 (Exhibit 7.06 to File No. 2-8047).
4.08	*	June 1, 1952 (Exhibit 4.08 to File No. 2-9631).
4.09	*	Oct. 1, 1954 (Exhibit 4.10 to File No. 2-12216).
4.10	*	Sept. 1, 1956 (Exhibit 2.09 to File No. 2-13463).
4.11	*	Aug. 1, 1957 (Exhibit 2.10 to File No. 2-14156).
4.12	*	July 1, 1958 (Exhibit 4.12 to File No. 2-15220).
4.13	*	Dec. 1, 1960 (Exhibit 2.12 to File No. 2-18355).
4.14	*	Aug. 1, 1961 (Exhibit 2.13 to File No. 2-20282).
4.15	*	June 1, 1962 (Exhibit 2.14 to File No. 2-21601).
4.16	*	Sept. 1, 1963 (Exhibit 4.16 to File No. 2-22476).
4.17	*	Aug. 1, 1966 (Exhibit 2.16 to File No. 2-26338).
4.18	*	June 1, 1967 (Exhibit 2.17 to File No. 2-27117).
4.19	*	Oct. 1, 1967 (Exhibit 2.01R to File No. 2-28447).
4.20	*	May 1, 1968 (Exhibit 2.01S to File No. 2-34250).

4.21	*	Oct. 1, 1969 (Exhibit 2.01T to File No. 2-36693).
4.22	*	Feb. 1, 1971 (Exhibit 2.01U to File No. 2-39144).
4.23	*	May 1, 1971 (Exhibit 2.01V to File No. 2-39815).
4.24	*	Feb. 1, 1972 (Exhibit 2.01W to File No. 2-42598).
4.25	*	Jan. 1, 1973 (Exhibit 2.01X to File No. 2-46434).
4.26	*	Jan. 1, 1974 (Exhibit 2.01Y to File No. 2-53235).
4.27	*	Sept. 1, 1974 (Exhibit 2.01Z to File No. 2-53235).
4.28	*	April 1, 1975 (Exhibit 4.01AA to File No. 2-71259).
4.29	*	May 1, 1975 (Exhibit 4.01BB to File No. 2-71259).
4.30	*	March 1, 1976 (Exhibit 4.01CC to File No. 2-71259).
4.31	*	June 1, 1981 (Exhibit 4.01DD to File No. 2-71259).
4.32	*	Dec. 1, 1981 (Exhibit 4.01EE to File No. 2-83364).
4.33	*	May 1, 1983 (Exhibit 4.01FF to File No. 2-97667).
4.34	*	Dec. 1, 1983 (Exhibit 4.01GG to File No. 2-97667).
4.35	*	Sept. 1, 1984 (Exhibit 4.01HH to File No. 2-97667).
4.36	*	Dec. 1, 1984 (Exhibit 4.01II to File No. 2-97667).
4.37	*	May 1, 1985 (Exhibit 4.36 to Form 10-K for the year 1985, File No. 1-3034).
4.38	*	Sept. 1, 1985 (Exhibit 4.37 to Form 10-K for the year 1985, File No. 1-3034).
4.39	*	July 1, 1989 (Exhibit 4.01 to form 8-K dated July 7, 1989, File No. 1-3034).
4.40	*	June 1, 1990 (Exhibit 4.01 to Form 8-K dated June 1, 1990, File No. 1-3034).
4.41	*	Oct. 1, 1992 (Exhibit 4.01 to Form 8-K dated Oct. 13, 1992, File No. 1-3034).
4.42	*	April 1, 1993 (Exhibit 4.01 to Form 8-K dated March 30, 1993, File No. 1-3034).
4.43	*	Dec. 1, 1993 (Exhibit 4.01 to Form 8-K dated Dec. 7, 1993, File No. 1-3034).
4.44	*	Feb. 1, 1994 (Exhibit 4.01 to Form 8-K dated Feb. 10, 1994, File No. 1-3034).
4.45	*	Oct. 1, 1994 (Exhibit 4.01 to Form 8-K dated Oct. 5, 1994, File No. 1-3034).
4.46	*	June 1, 1995 (Exhibit 4.01 to Form 8-K dated June 28, 1995, File No. 1-3034).
4.47	*	April 1, 1997 (Exhibit 4.47 to Form 10-K for the year 1997, File No. 1-3034).
4.48	*	March 1, 1998 (Exhibit 4.01 to Form 8-K dated March 11, 1998, File No. 1-3034).
4.49	**	May 1, 1999
4.50	**	June 1, 2000
4.51	**	August 1, 2000 (Assignment and Assumption of Trust Indenture)

4.52	*	Subordinated Debt Securities Indenture, dated as of Jan. 30, 1997, between Xcel Energy and Norwest Bank Minnesota, National Association, as trustee. (Exhibit 4.02 to Form 8-K dated Jan. 28, 1997, File No. 001-03034.)
4.53	*	Preferred Securities Guarantee Agreement, dated as of Jan. 31, 1997, between Xcel Energy and Wilmington Trust Company, as Trustee. (Exhibit 4.05 to Form 8-K dated Jan. 28, 1997, File No. 001-03034.)
4.54	**	Preferred Securities Guarantee Agreement, dated as of August 18, 2000, between Northern States Power Company and Wilmington Trust Company, as Trustee.
4.55	*	Amended and Restated Declaration of Trust of NSP Financing I, dated as of Jan. 31, 1997, including form of Preferred Security. (Exhibit 4.10 to Form 8-K dated Jan. 28, 1997, File No. 001-03034.)
4.56	*	Supplemental Indenture, dated as of Jan. 31, 1997, between Xcel Energy and Norwest Bank Minnesota, National Association, as trustee, including form of Junior Subordinated Debenture. (Exhibit 4.12 to Form 8-K dated Jan. 28, 1997, File No. 001-03034.)
4.57	**	Supplemental Trust Indenture dated August 18, 2000 between Xcel Energy, Northern States Power Company and Wells Fargo Bank Minnesota, National Association, as Trustee
4.58	*	Common Securities Guarantee Agreement dated as of Jan. 31, 1997, between Xcel Energy and Wilmington Trust Company, as Trustee. (Exhibit 4.13 to Form 8-K dated Jan. 28, 1997, File No. 001-03034.)
4.59	**	Common Securities Guarantee Agreement dated as of August 18, 2000, between NSP and Wilmington Trust Company, as Trustee.
4.60	*	Subscription Agreement, dated as of Jan. 28, 1997, between NSP Financing I and NSP. (Exhibit 4.14 to Form 8-K dated Jan. 28, 1997, File No. 001-03034.)
4.61	*	Trust Indenture, dated July 1, 1999, between NSP and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to Form 8-K dated July 21, 1999, File No. 1-03034.)
4.62	*	Supplemental Trust Indenture, dated July 15, 1999, between NSP and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.02 to Form 8-K dated July 21, 1999, File No. 1-03034.)
4.63	**	Supplemental Trust Indenture, dated August 18, 2000, among Xcel Energy, Northern States Power Company and Wells Fargo Bank Minnesota, National Association, as Trustee.
10.01	*	Facilities Agreement, dated July 21, 1976, between NSP and the Manitoba Hydro-Electric Board relating to the interconnection of the 500-kv line. (Exhibit 5.06I to File No. 2-54310.)
10.02	*	Transactions Agreement, dated July 21, 1976, between NSP and the Manitoba Hydro-Electric Board relating to the interconnection of the 500-kv line. (Exhibit 5.06J to File No. 2-54310.)
10.03	*	Coordinating Agreement, dated July 21, 1976, between NSP and the Manitoba Hydro-Electric Board relating to the interconnection of the 500-kv line. (Exhibit 5.06K to File No. 2-54310.)

10.04	*	Ownership and Operating Agreement, dated March 11, 1982, between NSP, Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3. (Exhibit 10.01 to Form 10-Q for the quarter ended Sept. 30, 1994, File No. 1-3034.)
10.05	*	Transmission Agreement, dated April 27, 1982, and Supplement No. 1, dated July 20, 1982, between NSP and Southern Minnesota Municipal Power Agency. (Exhibit 10.02 to Form 10-Q for the quarter ended Sept. 30, 1994, File No. 1-3034.)
10.06	*	Power Agreement, dated June 14, 1984, between NSP and the Manitoba Hydro-Electric Board, extending the agreement scheduled to terminate on April 30, 1993, to April 30, 2005. (Exhibit 10.03 to Form 10-Q for the quarter ended Sept. 30, 1994, File No. 1-3034.)
10.07	*	Power Agreement, dated August 1988, between NSP and Minnkota Power Company. (Exhibit 10.08 to Form 10-K for the year 1988, File No. 1-3034.)
10.08	**	Assignment and Assumption Agreement, dated August 18, 2000 between Northern States Power Company and Xcel Energy Inc.
16.01	*	Letter regarding change in accountant (Exhibit 16 to Xcel Energy Form 8-K dated August 21, 2000, File No. 1-3034)
99.01		Consolidated Financial Statements for the Nine Months Ended September 30, 2000 and September 30, 1999
99.02		Statement pursuant to Private Securities Litigation Reform Act of 1995
27.01		Financial Data Schedule for 1999
27.02		Financial Data Schedule for the Nine Months Ended September 30, 2000

SIGNATURES

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant has duly caused this amendment registration statement to be signed on its behalf by the undersigned, thereunto duly authorized.