NORTHERN STATES POWER CO /MN/, 10-K405, 2000-03-29

NORTHERN STATES POWER CO /MN/
10-K405, 2000-03-29
ELECTRIC & OTHER SERVICES COMBINED

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

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

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

For the fiscal year ended December 31, 1999

Commission file number: 1-3034

NORTHERN STATES POWER COMPANY
(Exact name of Registrant as specified in its charter)

Minnesota		41-0448030
(State or other jurisdiction of incorporation or organization) 414 Nicollet Mall, Minneapolis, Minnesota (Address of principal executive offices)		(I.R.S. Employer Identification No.) 55401 (Zip Code)

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

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

Title of Each Class		Name of each exchange on which registered
Common Stock, $2.50 Par Value		New York Stock Exchange, Chicago Stock Exchange and Pacific Stock Exchange
Cumulative Preferred Stock, $100 Par Value each
Preferred Stock $3.60 Cumulative		New York Stock Exchange
Preferred Stock $4.08 Cumulative		New York Stock Exchange
Preferred Stock $4.10 Cumulative		New York Stock Exchange
Preferred Stock $4.11 Cumulative		New York Stock Exchange
Preferred Stock $4.16 Cumulative		New York Stock Exchange
Preferred Stock $4.56 Cumulative		New York Stock Exchange
Trust Originated Preferred Securities 7⁷/8%		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. /x/

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

As of March 15, 2000, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $2,911,031,159 and there were 156,589,316 shares of common stock outstanding, $2.50 par value.

Documents Incorporated by Reference
None.

Index

		Page No.
PART I
Item 1–Business		1
PROPOSED BUSINESS COMBINATION		1
UTILITY REGULATION AND REVENUES
General		1
Revenues		2
Ratemaking Principles in Minnesota and Wisconsin		3
Fuel and Purchased Gas Adjustment Clauses		3
Resource Adjustment Clauses		4
Regulatory Matters by Jurisdiction		4
ELECTRIC UTILITY OPERATIONS
Competition and Industry Restructuring		7
Automated Meter Reading		9
Capability and Demand		9
Energy Sources		10
Fuel Supply and Costs		11
Nuclear Power—Operations and Waste Disposal		12
Electric Operating Statistics		14
GAS UTILITY OPERATIONS
Competition/Regulation		15
Business Growth		15
Standards		16
Capability and Demand		16
Gas Supply and Costs		16
Viking Gas Transmission Company		17
Gas Operating Statistics		19
NONREGULATED SUBSIDIARIES
NRG Energy, Inc.		19
Seren Innovations, Inc.		21
Energy Masters International, Inc.		22
Eloigne Company		22
Ultra Power Technologies, Inc.		22
Nonregulated Business Information		22
ENVIRONMENTAL MATTERS		23
CAPITAL SPENDING AND FINANCING		26
EMPLOYEES AND EMPLOYEE BENEFITS		26
Item 2–Properties		27
Item 3–Legal Proceedings		28
Item 4–Submission of Matters to a Vote of Security Holders		29
PART II
Item 5–Market for Registrant's Common Equity and Related Stockholder Matters		29
Item 6–Selected Financial Data		30
Item 7–Management's Discussion and Analysis of Financial Condition and Results of Operations		30
Item 7A–Quantitative and Qualitative Disclosures about Market Risk		45
Item 8–Financial Statements and Supplementary Data		45
Item 9–Changes in and Disagreements with Accountants Accounting and Financial Disclosure		87
PART III
Item 10–Directors and Executive Officers of the Registrant		87
Item 11–Executive Compensation		90
Item 12–Security Ownership of Certain Beneficial Owners and Management		97
Item 13–Certain Relationships and Related Transactions		98
PART IV
Item 14–Exhibits, Financial Statement Schedules, and Reports on Form 8-K		99
SIGNATURES		104
EXHIBIT (EXCERPT)
Statement Pursuant to Private Securities Litigation Reform Act of 1995
Unaudited Pro Forma Financial Information

PART I

Item 1—Business

Northern States Power Company (NSP-Minnesota) was incorporated in 1909 under the laws of Minnesota. Its executive offices are located at 414 Nicollet Mall, Minneapolis, Minnesota 55401 (Phone 612-330-5500). NSP-Minnesota has two significant subsidiaries, Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin), and NRG Energy, Inc. (NRG). NSP-Minnesota also has several other subsidiaries, including: Energy Masters International, Inc. (EMI); Viking Gas Transmission Company (Viking); Eloigne Company (Eloigne); Seren Innovations, Inc. (Seren); and Ultra Power Technologies, Inc. (Ultra Power). NSP-Minnesota and its subsidiaries are collectively referred to as NSP.

NSP is predominantly an operating 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, South Dakota and Arizona. NSP-Wisconsin serves retail customers in Wisconsin and Michigan. NRG operates several nonregulated energy businesses and is an equity investor in many nonregulated energy affiliates throughout the world.

Regulated electric and gas utility companies are facing 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. A growing portion of NSP's earnings comes from nonregulated operations. The nonregulated projects can carry a higher level of risk than NSP's traditional utility businesses. For further discussion of these matters, see Management's Discussion and Analysis under Item 7 and Notes to Financial Statements under Item 8.

Except for historical information, the matters discussed in this Form 10-K are forward-looking statements that are subject to certain risks, uncertainties and assumptions, as discussed in Management's Discussion and Analysis under Item 7 and Exhibit 99.01 to this report on Form 10-K.

PROPOSED BUSINESS COMBINATION

On March 24, 1999, NSP and New Century Energies, Inc. (NCE) agreed to merge and form a new entity, Xcel Energy Inc. In March 2000, the state of Arizona approved the merger and the waiting period under the Hart-Scott-Rodino Act expired. For more discussion of this proposed business combination, see Management's Discussion and Analysis under Item 7, Note 15 to the Financial Statements under Item 8 and Exhibit 99.03 and 99.04.

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

The Federal Energy Regulatory Commission (FERC) has jurisdiction over wholesale rates for electric transmission service and electric energy sold in interstate commerce, hydro facility licensing, the wholesale gas transportation rates of Viking, the siting and construction of facilities by Viking and certain other activities of NSP-Minnesota, NSP-Wisconsin and Viking. Federal, state and local agencies also have jurisdiction over many of NSP'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 is unable to predict the impact on its operating results from the future regulatory activities of any of the above agencies. NSP strives to comply with all rules and regulations issued by the various agencies.

Revenues

NSP's financial results depend, in part, on its ability to obtain adequate and timely rate relief from the various regulatory bodies, its ability to control costs and the success of its nonregulated activities. NSP's 1999 utility operating revenues, excluding non-firm electric sales to other utilities of $144 million and miscellaneous electric and gas revenues of $71 million, were subject to regulatory jurisdiction as follows:

	Authorized Return on Common Equity at Dec. 31, 1999				Percent of Total 1999 Utility Revenues
	Electric		Gas		(Electric & Gas)
Retail:
Minnesota Public Utilities Commission	11.47	%	11.4	%**	75.4	%
Public Service Commission of Wisconsin	11.9		11.9		14.1
North Dakota Public Service Commission	11.5		12.0	**	5.1
South Dakota Public Utilities Commission	*				3.3
Michigan Public Service Commission	11.9		12.62		0.5
Arizona Corporation Commission			10.5	**	0.2
Sales for Resale—Wholesale, Viking Gas and Interstate
Transmission: Federal Energy Regulatory Commission	*			*	1.4
Total					100.0	%

*: 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)
(Millions of dollars)		Annual Increase/(Decrease)
(Millions of dollars)	Year	Requested		Granted
	1995	(0.8	)	(0.8	)
	1996	2.2		(2.8	)
	1997	—		—
	1998	29.5		18.8
	1999	3.3		1.1

Ratemaking Principles in Minnesota and Wisconsin

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.

The PSCW has a biennial filing requirement. By June of each odd-numbered year, NSP-Wisconsin must submit filings for calendar years beginning the following January. The filing procedure and review generally allow the PSCW sufficient time to issue an order effective with the start of the test year.

The PSCW reviews each utility's cash position to determine if a current return on CWIP will be allowed. The PSCW will allow either a return on CWIP or capitalization of AFC at the adjusted overall cost of capital. NSP-Wisconsin currently capitalizes AFC on production and transmission CWIP at the FERC formula rate and on all other CWIP at the adjusted overall cost of capital.

Fuel and Purchased Gas Adjustment Clauses

NSP-Minnesota's retail electric rate schedules and most of NSP-Wisconsin's wholesale electric rate schedules provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy. NSP-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.

NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers. In lieu of fuel clause recovery, a procedure is in place that compares actual monthly and anticipated annual fuel costs with those costs that were included in the latest retail electric rates. If the comparison results in a difference outside a prescribed range, the PSCW may hold hearings limited to fuel costs and revise rates. Any revised rates would be effective until the next rate case. The adjustment approved is calculated on an annual basis, but applied prospectively.

Gas rate schedules for NSP-Minnesota, NSP-Wisconsin and Black Mountain Gas (BMG) in Arizona 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 factors in Minnesota and Wisconsin are calculated for the current month based on the estimated purchased gas costs for that month. In Arizona, the factor is based on actual gas costs with a two-month lag.

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.

During 1999, the PSCW approved a new Gas Cost Recovery Mechanism (GCRM) to replace the PGA. The financial impact of the new gas cost recovery mechanism is substantially the same as with the former PGA. Approximately 70 percent of NSP-Wisconsin's gas revenues represent recovery of gas costs through the GCRM mechanism.

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

Viking provides interstate gas transportation services only and does not sell gas. Viking makes incidental purchases and sales of natural gas to balance the volumes of gas in the pipeline. In 1998, the FERC approved a tariff change to reflect the costs and revenues from those incidental transactions on a true-up basis, similar to a PGA mechanism.

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 Public Utilities Commission (MPUC)

During 1999, NSP recorded charges to earnings of $35 million (before tax), or approximately 14 cents per share, 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 did not accrue any conservation incentives for 1999 activity. See Management's Discussion and Analysis under Item 7 for discussion of this issue.

On July 27, 1999, the MPUC issued an order requiring an investigation into the reasonableness of NSP's retail electric rates in Minnesota. As required by the rate investigation order, NSP 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's filing, closed the investigation and transferred any further analysis to the NSP-NCE merger proceeding.

During 1999, NSP obtained approval from the MPUC to include the cost of electricity futures and options in the fuel clause. This approval allows NSP 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 Public Service Commission (NDPSC)

In July 1998, the NDPSC ordered its staff to conduct an investigation of NSP's North Dakota jurisdictional electric earnings. The purpose of the investigation was to determine if existing rates wer fair and reasonable given earnings results. In December 1999, NDPSC Staff issued an investigation report finding NSP to be in an excess revenue position of about $0.8 million. In January 2000, NSP entered into a settlement agreement with NDPSC staff. The settlement calls for a $250,000 electric rate reduction, closing of the earnings investigation case, the NDPSC approval of NSP's pending application to merge with NCE and the filing of a performance-based regulation plan within 10 days of the NDPSC merger approval.

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

South Dakota Public Utilities Commission (SDPUC)

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

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

Public Service Commission of Wisconsin (PSCW)

On Oct. 28, 1999, the PSCW approved NSP-Wisconsin's application for authority to maintain base retail electric and natural gas service rates in Wisconsin at current levels through 2001. Current rates were placed in effect September 1998.

On Feb. 14, 2000, NSP-Wisconsin filed an application with the PSCW to increase electric rates for fuel costs. In its application, NSP-Wisconsin noted that 2000 fuel costs are forecast to be approximately $12 million above authorized levels, primarily due to higher purchased power costs. The application is currently pending before the PSCW, and a decision is expected in the second quarter of 2000. The amount of cost recovery and the effective date of the potential surcharge will be determined upon completion of the regulatory process. If NSP-Wisconsin's application is approved, a surcharge would be added to customer bills for the remainder of 2000 and all of 2001.

Under the PSCW biennial rate filing rule, NSP-Wisconsin anticipates filing a general electric and gas rate case by June 1, 2001.

Michigan Public Service Commission (MPSC)

In January 1999, the MPSC approved a settlement agreement authorizing NSP-Wisconsin to restructure electric rates for its Michigan customers. The restructuring does not affect total revenues. Return on equity was set at 11.9 percent.

No general rate filings are anticipated in Michigan in 2000.

Arizona Corporation Commission (ACC)

In July 1998, the ACC approved the sale of Black Mountain Gas (BMG) assets and transfer of BMG's Certificate of Convenience and Necessity to NSP. As part of the approval, BMG filed an application with the ACC for a 21.6 percent decrease in gas rates. In October 1999, the parties filed an Agreement and a Proposed Opinion and Order requesting an overall decrease of $495,000. A rate order was received in December 1999 confirming this decision.

As part of the approval and transfer process, BMG was required to file a rate application for its Cave Creek Division by April 1, 2000, which will accommodate a full calendar test year for the ratemaking process.

Federal Energy Regulatory Commission (FERC)

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. See Management's Discussion and Analysis under Item 7 for discussion of these rules.

In the first quarter of 1998, NSP filed wholesale electric point-to-point and network integration transmission service (NTS) rate cases with the FERC. In March 1999, NSP 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'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 to interrupt service to its own retail customers proportionally with curtailment of wholesale transmission-only customers taking service under NSP's Order No. 888 transmission tariff. When NSP's transmission lines are constrained or about to become overloaded, the FERC order would have required NSP 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 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 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.

In May 1999, a majority of the members of the Mid-Continent Area Power Pool (MAPP) voted to approve a MAPP regional transmission service tariff. The MAPP tariff would supersede MAPP members' individual electric transmission service tariffs for most wholesale transactions. The proposed MAPP tariff was filed with the FERC in June 1999. MAPP proposed the new tariff be effective 90 days after a FERC order accepting the tariff for filing. When effective, MAPP's tariff could reduce NSP's pretax earnings due to lower revenues and/or higher costs. The tariff is pending FERC action. While there is a small probability that the tariff could take effect as early as July 1, 2000, which would result in a $6 million pretax impact in 2000, NSP anticipates continued regulatory delay to tariff implementation, resulting in minimal or no impact on NSP's 2000 pretax earnings.

In June 1998, Viking filed a rate case with the FERC, requesting a $3 million annual rate increase. In 1999, a settlement agreement was reached that provided Viking an annual rate increase of approximately

$1.3 million, or 6 percent, effective Jan. 1, 1999, and a four year phased rate roll-in for the cost of Viking's 1996 and 1997 expansion projects. FERC approved this settlement in May 1999.

ELECTRIC UTILITY OPERATIONS

Competition and Industry Restructuring

NSP'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 cannot predict the extent to which its future business may be affected by competition, NSP 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 may be required to separate the functions of power generation, transmission, distribution and energy services. NSP cannot predict the ultimate result of restructuring. However, NSP is 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. For more information on these actions, see Management's Discussion and Analysis under Item 7.

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.

In compliance with FERC Orders No. 888 and 889, NSP has separated personnel who perform the merchant function, which includes power and energy marketing, from personnel who perform the transmission system operation function. NSP'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's transmission system.

In 1998, NSP expanded its wholesale energy marketing efforts by formally establishing an Energy Marketing division. Energy Marketing is responsible for meeting the requirements of NSP's retail and wholesale electric customers for low-cost energy while optimizing earnings from NSP'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 has contracts with several municipal customers, a competitive market requires NSP to remain competitive in the entire wholesale market because many parties, including power marketers, are now able to use NSP'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, such as Michigan, 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 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 Legislature in January 1999, concluding that additional study was necessary. The 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.

Due to reliability concerns, the PSCW turned its focus from restructuring the electric utility industry to developing the utility infrastructure necessary to assure reliable electric service. In 1998, Wisconsin Act 204, "the Reliability Act," became law. The Reliability Act contains a number of steps necessary for industry restructuring, including streamlining and updating the regulatory process. During 1999, an electric reliability bill was passed that included further steps necessary to move towards a restructured industry. Major components included some relief from a restriction on the amount of nonutility assets that a Wisconsin utility holding company can own, a requirement that eastern Wisconsin utilities join an eastern Wisconsin transmission company, and mandated public benefits encompassing low-income energy assistance, conservation programs and renewable and environmental research. The bill also included a renewable portfolio mandate, local impact fees for new transmission lines and nitrogen oxide (NOx) protections for MAPP utilities.

The effects on NSP-Wisconsin include:

•: an increase in the amount of money that must be collected from NSP-Wisconsin's customers to fund low-income assistance and conservation programs, and renewable and environmental research, and
•: partial protection from potential costs related to the proposed NOx emission regulations.

NSP-Wisconsin is not affected by the renewable mandate since it already relies significantly on renewable sources of energy. Although activity has taken place at the Legislature that should ultimately provide for a competitive energy market, at this time a definitive timeline has not yet been established for the implementation of retail competition in Wisconsin.

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.

In 1998, the MPSC reaffirmed its order to open Michigan's retail electricity market to competition. The initial order directed large Michigan utilities to open 2.5 percent of their electric load to competition each year from 1997 to 2001. In 2002, all Michigan electric customers would have access to a competitive market. The larger Michigan utilities challenged this order. The lower courts upheld the MPSC's authority to implement retail competition. However, the State Supreme Court ruled the MPSC does not have the authority to order retail competition, but may allow it if utilities proceed voluntarily. The smaller Michigan utilities, including NSP-Wisconsin, have not elected to offer customer choice at this time. A coalition of businesses and a few utilities, working through the Michigan Chamber of Commerce, have introduced a bill to mandate customer choice by January 2002. The smaller utilities continue to work with the Chamber and legislators to include provisions that take into consideration the unique situation of the smaller utilities in terms of multi-state territory, implementation costs to customers and the effective date.

NSP 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 to take advantage of the developing competition in this sector of the industry. NSP's proposal, which has been approved by the MPUC, allows NRG and NSP's generation business unit to bid in response to company solicitations for proposals.

NSP 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 will continue to work with regulators to develop a tariff and infrastructure that will support a competitive electric environment. NSP is positioning itself for the competitive environment by offering value-added services tied to our core businesses.

Automated Meter Reading

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

Capability and Demand

NSP's 1999 maximum demand of 7,990 Mw occurred on July 29, 1999. Resources available at that time included 7,176 Mw of company-owned capability and 2,024 Mw of purchased capability, net of contracted sales. NSP carried a reserve margin for 1999 of 15 percent to avoid the MAPP penalty for reserve shortfalls. As a member of MAPP, NSP 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. NSP'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, NSP expects its 2000 summer electric peak demand to be 7,696 Mw. NSP expects to meet its summer peak and the MAPP reserve requirements through a combination of generation and purchases. See Note 14 of Notes to Financial Statements under Item 8 for more discussion of power agreement commitments.

During 1998 NSP filed an electric resource plan with the MPUC for the period 1998 to 2012. The plan describes how NSP 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 NSP's peak demand and conserve overall electricity use, an approximate schedule of power purchase solicitations to meet increasing demand, and programs and plans to maintain the reliable operation of existing resources. In summary, the plan:

•: Forecasts 1.7 percent annual growth in NSP's energy and peak demand requirements.
•: Outlines NSP's 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 NSP 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 NSP 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 add 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 continues to implement various demand side management (DSM) programs designed to improve load factor and reduce NSP's power production costs and system peak demands, reducing or delaying the need for additional investment in new generation and transmission facilities. NSP offers 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 NSP's service and help NSP's customer base become more energy efficient and competitive. NSP's DSM programs have reduced system peak demand by approximately 1,381 Mw.

Energy Sources

During 1999, 42 percent of NSP's kwh requirements were obtained from coal generation and 28 percent were obtained from nuclear generation. Purchased and interchange energy provided 26 percent,

including 11 percent from Manitoba Hydro; NSP's hydro and other fuels provided the remaining 4 percent. The following is a summary of NSP's electric power output in millions of kwh for the past three years:

	1999	1998	1997
Thermal plants	34,091	32,902	31,896
Hydro plants	845	696	1,015
Purchased and interchange	12,397	12,529	10,661

Total	47,333	46,127	43,572

In 1999, NSP filed with the MPUC its plan to repower two coal-fired units at its 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 NSP's 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 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 NSP's financial results. For more information, see Management's Discussion and Analysis under Item 7.

Fuel Supply and Costs

Coal and nuclear fuel will continue to dominate NSP's regulated utility fuel requirements for generating electricity by NSP-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	57.5	%	58.5	%	58.7	%
Nuclear	38.4	%	36.4	%	36.7	%
Other	4.1	%	5.1	%	4.6	%

NSP normally maintains between 20 and 40 days of coal inventory at each plant, depending on the plant site. NSP 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, NSP expects more than 98 percent of the coal it burns in 2000 will have a sulfur content of less than 1 percent. NSP 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 will purchase approximately 10 percent of its coal requirements in a large active spot market if prices are more favorable than contracted prices.

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

To operate NSP's nuclear generating plants, NSP secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication. The contract strategy involves a portfolio of spot purchases and medium and long-term contracts for uranium, conversion and enrichment.

Current contracts are flexible and cover 100 percent of uranium, conversion and enrichment requirements through the year 2000. These contracts expire at varying times between 2000 and 2005. The overlapping nature of contract commitments will allow NSP to maintain 50 percent to 100 percent coverage beyond 2000. NSP 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's average electric fuel costs for the past three years are shown below:

	Fuel Costs Per Million Btu
	1997		1998		1999
Coal*	$	1.05	$	1.00	$	1.10
Nuclear		.47		.47		.48
Composite All Fuels		.88		.85		.88

*: Includes refuse-derived fuel and wood.

Nuclear Power—Operations and Waste Disposal

NSP operates 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.

In September 1998, NSP 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 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'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 and Barnwell currently operate under an annual contract, while NSP uses the Envirocare facility through various low-level waste processors. NSP 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.

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 3—Legal Proceedings and Note 13 to the Financial Statements under Item 8 for further discussion of this matter.

NSP, with regulatory and legislative approval, has been providing on-site storage at its Monticello and Prairie Island nuclear plants. In 1979, NSP began expanding the used nuclear fuel storage facilities at its Monticello plant by replacement of the racks in the storage pool. In 1987, NSP completed the shipment of 1,058 used fuel assemblies from the Monticello plant to a General Electric storage facility in Morris, Ill. 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, 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 to install 17 spent fuel casks at Prairie Island. NSP 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 to obtain the Prairie Island temporary nuclear fuel storage facility approval. NSP has implemented programs to meet the legislative commitments. For more information on the status of these legislative commitments, see Note 14 to the Financial Statements under Item 8.

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

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

Electric Operating Statistics

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

	1999			1998		1997		1996		1995
Revenues (thousands)
Residential	$	809 528		$	774 803	$	739 684	$	727 145	$	735 743
Small commercial and industrial		405 620			389 744		379 848		376 797		362 521
Medium commercial and industrial		489 633			466 352		433 526		401 137		399 259
Large commercial and industrial		504 195			483 595		468 404		450 811		448 226
Streetlighting and other		31 668			31 054		30 826		30 033		29 162
Conservation accrual adjustments *		(71 348	)		6 673		2 185		4 577		(666	)

Total retail		2 169 296			2 152 221		2 054 473		1 990 500		1 974 245
Sales for resale		168 581			149 707		107 464		98 961		133 961
Transmission and other		59 219			60 423		56 613		37 952		34 564

Total	$	2 397 096		$	2 362 351	$	2 218 550	$	2 127 413	$	2 142 770

Sales (millions of kilowatt-hours)
Residential		10 373			10 127		9 791		9 847		9 956
Small commercial and industrial		6 117			5 999		5 907		6 091		5 763
Medium commercial and industrial		8 981			8 801		8 263		7 470		7 511
Large commercial and industrial		11 283			11 277		11 059		11 089		10 941
Streetlighting and other		325			327		335		336		329

Total retail		37 079			36 531		35 355		34 833		34 500
Sales for resale		6 724			6 304		4 658		4 929		6 500

Total		43 803			42 835		40 013		39 762		41 000

Customer accounts (at Dec. 31) **
Residential		1 306 900			1 287 080		1 273 161		1 252 476		1 238 576
Small commercial and industrial		160 880			155 536		150 103		149 134		144 774
Medium commercial and industrial		9 731			9 510		9 142		7 962		7 906
Large commercial and industrial		762			727		695		669		652
Streetlighting and other		6 365			6 243		6 276		5 030		4 883

Total retail		1 484 638			1 459 096		1 439 377		1 415 271		1 396 791
Sales for resale		82			78		59		54		67

Total		1 484 720			1 459 174		1 439 436		1 415 325		1 396 858

*: 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 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). NSP also serves portions of eastern North Dakota, the cities of Page, Carefree, North Phoenix, North Scottsdale and Cave Creek in Arizona and the cities of Eau Claire, LaCrosse, Ashland and New Richmond in Wisconsin.

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 provides unbundled transportation service. Transportation service does not have an adverse effect on earnings because NSP's sales and transportation rates have been designed to make NSP 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 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 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 NSP's system.

In 1997, the MPUC approved NSP-Minnesota's 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's gas utility customer base grew by approximately 20,000 customers during 1999. In addition to exploring new growth opportunities, NSP is also focusing on conversion of potential customers who are located near NSP's gas mains, but are not connected to the service.

In December 1999, NSP-Minnesota merged with Natrogas Inc. Natrogas, based in Minneapolis, has approximately 20,000 natural gas and propane customers in four states. In July 1998, NSP-Minnesota merged with BMG, located in Cave Creek, Ariz. BMG is a natural gas and propane distribution company with approximately 6,500 customers. Also in July 1998, NSP-Wisconsin completed its merger with Natural Gas Inc. (NGI) of New Richmond, Wis. NGI has approximately 1,900 customers. All three of these mergers were structured as tax-free reorganizations for income tax purposes and were accounted for using the pooling of interests method. Prior period financial statements have not been restated due to immateriality.

In January 1999, NSP filed for MPUC, ACC and NDPSC approval to transfer the BMG operations into a wholly owned subsidiary of NSP. NSP believes this structure will provide more efficient management and regulation, and will comply with the Public Utility Holding Company Act. The transaction has been approved by the states and is pending final SEC approval.

NSP-Minnesota's gas operation maintains 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 NSP-Minnesota's service territory.

In February 2000, the FERC issued new rules expanding the scope of conduct applicable to interstate gas pipelines (like Viking) with gas marketing affiliates.

Standards

FERC rules incorporate standard natural gas business practices approved by the Gas Industry Standards Board (GISB). The rules and standards apply to interstate gas pipelines such as Viking, and are intended to simplify transportation of natural gas across the interstate gas pipeline grid. GISB and FERC continue to revise the standards periodically, requiring incremental expenditures by Viking and NSP.

In January 1997, the PSCW adopted standards of conduct for natural gas LDCs serving Wisconsin consumers. The standards are similar to, but much more extensive than, the standards of conduct imposed by the FERC. The PSCW standards require separation of the LDC delivery function from any affiliate that engages in gas functions and impose extensive reporting and other administrative requirements. NSP-Wisconsin's compliance plan was approved during 1999.

Capability and Demand

NSP categorizes its gas supply requirements as firm or interruptible (customers with an alternate energy supply). NSP's maximum daily sendout (firm and interruptible) of 782,702 mmBtu for 1999 occurred on Jan. 4, 1999.

NSP 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 620,500 mmBtu/day. In addition, NSP has contracted with providers of underground natural gas storage services. Using storage reduces the need for firm pipeline capacity. These storage agreements provide NSP storage for approximately 19 percent of annual and 30 percent of peak daily, firm requirements.

NSP also owns and operates two LNG plants with a storage capacity of 2.5 bcf equivalent and four propane-air plants with a storage capacity of 1.4 Bcf equivalent to help meet the peak requirements of its firm residential, commercial and industrial customers. These peak-shaving facilities have production capacity equivalent to 246,000 mcf of natural gas per day, or approximately 32 percent of peak day firm requirements. NSP's LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days and can be used to minimize daily imbalance fees on interstate pipelines.

Gas utilities in Minnesota are required to file for a change in gas supply contract levels to meet peak demand, to redistribute demand costs among classes, or exchange one form of demand for another. In March 1999, the MPUC approved NSP's 1998-99 entitlement levels, which allow NSP-Minnesota to recover the demand entitlement costs associated with the increase in transportation and storage levels in its monthly PGA. NSP-Minnesota's filing for approval of its 1999-2000 entitlement levels is pending MPUC action.

Gas Supply and Costs

NSP's natural gas supply commitments have been unbundled from its gas transportation and storage commitments. NSP's 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's retail gas customers are served from the

Northern pipeline system. NSP has firm gas transportation contracts with the following pipelines, which expire in various years from 2000 through 2013.

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

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

In addition to these fixed transportation charge obligations, NSP has 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 $17 million. These agreements allow NSP to purchase natural gas at a high load factor at rates below the prevailing market price, reducing the total cost per mmBtu.

NSP has certain gas supply and transportation agreements that include obligations for the purchase and/or delivery of specified volumes of gas or to make payments in lieu of. At Dec. 31, 1999, NSP was committed to approximately $236 million in such obligations under these contracts, which range from the years 2000-2013. NSP has negotiated market out clauses in its new supply agreements, which reduce NSP's purchase obligations if NSP no longer provides merchant gas service.

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

The following table summarizes the average cost per mmBtu of gas purchased for resale by NSP's regulated retail gas distribution business, which excludes Viking.

	NSP-Minnesota		NSP-Wisconsin
1997	$	3.33	$	3.22
1998	$	2.87	$	2.96
1999	$	2.86	$	2.91

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 are subject to approval by the MPUC. The MPUC has approved all NSP-Minnesota's transportation contracts with Viking.

Viking Gas Transmission Company

Acquired by NSP in 1993, Viking owns and operates a 670-mile interstate natural gas pipeline serving portions of Minnesota, Wisconsin and North Dakota, with a capacity of approximately 510 mcf per day. The Viking pipeline currently serves 10 percent of NSP's gas distribution system needs. Viking operates exclusively as a transporter of natural gas for third-party shippers under authority granted by the FERC. In addition to revenue derived from FERC-approved rates, Viking is receiving intercompany revenues from NSP-Minnesota for its jurisdictional allocations of the acquisition adjustment paid by NSP (in excess of carrying value) to acquire Viking. NSP-Minnesota is not currently recovering this cost in retail gas rates in

Minnesota, but is recovering this cost in North Dakota. NSP-Wisconsin recovered a portion of the cost in its retail gas rates through 1998.

As a natural gas pipeline, Viking is subject to FERC standards of conduct in its transactions with NSP-Minnesota and NSP-Wisconsin. Viking must transact with NSP on a non-discriminatory basis and certain restrictions are imposed on the retail gas operations of NSP-Minnesota and NSP-Wisconsin.

In 1997, Viking, in partnership with TransCanada PipeLines, Ltd. and NICOR, Inc., formed Viking Voyageur Gas Transmission Company LLC. The purpose of the Voyageur project was to install a new 773-mile pipeline parallel to the existing Viking pipeline and extending into the Chicago area. The Voyageur project did not receive the necessary shipper support to make the project viable. In April 1998, Viking withdrew from the proposed Voyageur pipelineproject and wrote off $1.4 million in costs related to the Voyageur project. During 1999, Viking reached a settlement with TransCanada and NICOR. Viking purchased all engineering and other studies related to the Voyageur project for approximately $4.7 million. Since the studies obtained through the settlement have continuing value to Viking, the payment has been capitalized as plant.

In May 1999, Viking received FERC approval to expand its transmission system in northwestern and central Minnesota by installing 45 miles of 24-inch pipeline. The $22 million expansion project was completed in November 1999 and increased capacity by 28,200 dekatherms per day.

In March 1999, Viking, WICOR and CMS Energy Corp. announced plans to build an interstate natural gas pipeline to serve the growing needs of the northern Illinois and southeastern Wisconsin markets. The three energy companies will each own an equal share of the proposed pipeline. The project, called the Guardian Pipeline, will transport natural gas from a hub near Joliet, Ill. to the Ixonia, Wis., area. The 147-mile pipeline is projected to initially carry about 750 mcf of natural gas per day, and depending on market conditions, can be expanded to 1.1 bcf per day. The total cost of the project is estimated to be $230 million. In December 1999, Guardian filed for a FERC certificate of public convenience and necessity, which would authorize construction.

Gas Operating Statistics

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

	1999			1998			1997			1996			1995
Revenue (thousands)
Residential	$	237 976		$	226 936		$	253 065		$	267 130		$	215 543
Commercial and industrial
Firm		130 066			124 099			144 539			146 145			119 863
Interruptible		63 376			61 050			79 135			63 585			48 646
Other		151			114			34			153			1 686

Total Retail		431 569			412 199			476 773			477 013			385 738
Interstate transmission (Viking)		25 172			23 375			19 809			17 553			16 328
Agency, transportation and off-system sales		18 372			23 792			21 287			34 662			26 122
Elimination of Viking sales to NSP		(3 198	)		(2 543	)		(2 673	)		(2 435	)		(2 374	)

Total	$	471 915		$	456 823		$	515 196		$	526 793		$	425 814

Sales (thousands of mmBtu)
Residential		40 658			37 522			42 428			48 149			42 294
Commercial and industrial
Firm		26 584			24 410			28 880			31 748			28 275
Interruptible		23 732			23 201			25 898			23 210			22 408
Other		97			48			33			394			772

Total retail		91 071			85 181			97 239			103 501			93 749

Other gas delivered (thousands of mmBtu)
Interstate transmission (Viking)		167 360			168 187			166 588			161 972			152 952
Agency, transportation and off-system sales		13 773			15 609			11 701			17 535			19 679
Elimination of Viking sales to NSP		(15 114	)		(14 563	)		(17 145	)		(19 311	)		(20 440	)

Total other gas delivered		166 019			169 233			161 144			160 196			152 191

Customer accounts (at Dec. 31)*
Residential		443 692			430 240			410 773			398 723			386 007
Commercial and industrial		50 886			44 523			41 905			40 244			38 575

Total retail		494 578			474 763			452 678			438 967			424 582
Other gas delivered		63			58			36			30			62

Total		494 641			474 821			452 714			438 997			424 644

*: 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.

NONREGULATED SUBSIDIARIES

NRG Energy, Inc.

NRG is a leading participant in the independent power generation industry. NRG is principally engaged in the acquisition, development and operation of, and ownership of interests in, independent power production and co-generation facilities, thermal energy production and transmission facilities, landfill gas collection and associated electric generation facilities and resource recovery facilities.

At Dec. 31, 1999, NRG had interests in power generation facilities, including those under construction, with a total design capacity of 20,728 Mw. Of this amount, NRG has or will have complete or shared operational responsibility for 14,782 Mw and net ownership of, or leasehold interests in, 10,990 Mw.

NRG has interests in district heating and cooling systems and steam generation and transmission operations. As of Dec. 31, 1999, these thermal businesses had a steam capacity of approximately 3,835 mmBtu per hour, of which NRG's interest was 3,400 mmBtu per hour.

NRG has an ownership or operating interest in refuse-derived fuel plants, which processed more than 1,277,000 tons of municipal solid waste into approximately 1,063,000 tons of refuse-derived fuel during 1999.

NRG conducts business domestically and internationally through various subsidiaries, including: NRG International, Inc.; NEO Corporation; NRG Energy Center, Inc; NRG Operating Services, Inc.; NRG Northeast Generating LLC; NRG South Central Generating LLC; and other businesses and affiliates.

The summary on page 22 describes NRG's most significant projects. Additional information is included in Item 1 of NRG's 1999 Form 10-K, which is incorporated by reference via Exhibit 99.02.

NRG New Business Development

NRG is pursuing several energy-related investment opportunities, including those discussed further, and continues to evaluate other opportunities as they arise. Potential capital requirements for these opportunities are discussed in the Management's Discussion and Analysis under Item 7.

In April 1999, NRG acquired the Somerset power station for approximately $55 million from Eastern Utilities Associates. The Somerset station, located in Somerset, Mass., includes two coal-fired generating facilities and two aeroderivative combustion turbine peaking units with a nominal capacity rating of 160 Mw. NRG owns a 100 percent interest in the project. In connection with this acquisition, NRG entered into a Wholesale Standard Offer Service Agreement in which NRG is obligated to provide approximately 30 percent of the energy and capacity requirements of certain EUA affiliates (which is estimated to be approximately 275 Mw at peak requirement) until Dec. 31, 2009.

In May 1999, NRG and Dynegy acquired the Encina generating station and 17 combustion turbines for approximately $356 million from San Diego Gas & Electric Company. The facilities, which have a combined capacity of 1,218 Mw, are located near Carlsbad and San Diego, Calif. NRG and Dynegy each own a 50 percent interest.

In June 1999, NRG acquired the Huntley and Dunkirk generating stations from Niagara Mohawk Power Corp. (NIMO) for approximately $355 million. The two coal-fired plants are located near Buffalo, N.Y., and have a combined summer capacity of 1,360 Mw. NRG owns a 100 percent interest in the project. In connection with this acquisition, NRG entered into several Transition Power Purchase Agreements in which NIMO will purchase energy and capacity from these facilities for four years. NRG has agreed to sell 100 percent of the capacity of and an option to purchase up to 39 percent of the annual energy output from the Dunkirk facility to NIMO at fixed prices.

In June 1999, NRG acquired the Arthur Kill generating station and the Astoria gas turbine site for approximately $505 million from Consolidated Edison Company (ConEd). These facilities, which are located in the New York City area, have a combined summer capacity of 1,456 Mw. NRG owns a 100 percent interest in these projects. In connection with these acquisitions, NRG has agreed to sell to ConEd energy from the Arthur Kill and Astoria facilities at a fixed price in varying amounts, as specified by ConEd, up to the full capability of each facility. In addition, NRG has agreed to sell to ConEd at a fixed price, during certain periods, up to 100 percent of the capacity of the Arthur Kill generating facility and Astoria gas turbines facility.

In August 1999, a U.S. district judge issued a settlement order clearing the way for Louisiana Generating LLC to be confirmed as the winning bidder for Cajun Electric Power Cooperative's 1,708 Mw of fossil-fueled generation. NRG currently owns 100 percent of Louisiana Generating. It is expected that output from the base-load Cajun facility will be sold principally under long-term contracts. The acquisition, for approximately $1 billion, is expected to close at the end of the first quarter of 2000.

In October 1999, NRG purchased the 1,700-Mw oil and gas-fired Oswego generating station, located in Oswego, N.Y., for approximately $85 million from Niagara Mohawk Power Corporation and Rochester Gas and Electric Corporation. NRG owns a 100 percent interest in the project.

In November 1999, NRG agreed to purchase the 665-Mw Killingholme A station from National Power plc. Killingholme A was commissioned in 1994 and is a combined-cycle, gas-turbine power station located in England. The purchase price for the station will be approximately 410 million pounds sterling (approximately $662 million at end-of-year exchange rates) subject to commercial adjustments.

In December 1999, NRG purchased gas and oil electric generating stations with a combined capacity of 2,235 Mw for $460 million from Connecticut Light & Power Company (CL&P). The facilities are located throughout Connecticut. NRG owns a 100 percent interest in the project. NRG entered into a Standard Offer Service Wholesale Sales Agreement with CL&P. NRG will supply CL&P with 35 percent of its standard offer service load during 2000, 40 percent during 2001 and 2002 and 45 percent during 2003.

In December 1999, NRG purchased a 50 percent interest in the Rocky Road Power Plant, a 250-Mw natural gas-fired simple-cycle peaking facility in East Dundee, Ill., from Dynegy Inc. for approximately $60 million. The power plant began commercial operations on June 30, 1999, and received approval in October 1999 for the installation of an additional 100-Mw natural gas combustion turbine, increasing the facilities generating capacity to 350 Mw. The expansion is expected to be in service before the start of the peak summer 2000 season.

In December 1999, NRG sold a portion of its ownership interest in Cogeneration Corp. of America (CogenAmerica) to Calpine Corp. As a result of the sale, NRG recorded a gain of approximately 3 cents per share and reduced its ownership stake in CogenAmerica from 45 percent to 20 percent.

In January 2000, NRG reached agreement to purchase 1,875 Mw of fossil-fueled electric generation assets in the Northeast region of the United States from Conectiv. The purchase price is approximately $800 million. NRG will sell 500 Mw of energy around the clock to Delmarva Power and Light Company under a five-year agreement. The remaining energy and capacity will be sold into the markets in the Northeast region of the United States. NRG will own a 100 percent interest in the project.

In February 2000, NRG executed a memorandum of understanding with GE Power Systems, a division of General Electric Company, to purchase 11 gas turbine generators and five steam turbine generators over the next five years for approximately $500 million. NRG intends to install the 16 turbines, having a combined capacity of 3,000 Mw, at its existing North American plant sites.

NRG has a 25 percent equity interest in the Enfield Energy Centre Ltd., a 396-Mw natural gas power project located in England. The power station is expected to begin commercial operations in 2000. The power station will sell its output to the UK grid.

Seren Innovations, Inc.

Seren was formed in November 1996 to pursue communications and data services business. Seren is constructing a combination cable television, telephone and high-speed Internet access system in Minnesota, California and Colorado. Seren is pursuing additional development in other markets.

Energy Masters International, Inc.

EMI began operations in 1993. EMI primarily offers retrofitting and upgrading facilities for greater energy efficiency on a national basis. In 1995, EMI acquired Energy Masters Corporation, a company that specializes in energy efficiency improvement services for commercial, industrial and institutional customers. In 1997, EMI acquired 100 percent of Energy Solutions International Inc., an energy management firm.

In 1995, EMI and Atlantic Energy Enterprises established Enerval LLC, which provided natural gas services in the northeast United States. EMI's investment in Enerval was written down to an estimate of its net realizable value in 1997. In 1998, EMI sold its interest in Enerval.

Eloigne Company

Eloigne was established in 1993 and its principal business is the acquisition of rental housing projects that qualify for low-income housing tax credits under current federal tax law. As of Dec. 31, 1999, approximately $76 million had been invested in Eloigne projects, including approximately $22 million in wholly owned properties and approximately $54 million in equity interests in jointly-owned projects. These investments and related working capital requirements have been financed with approximately $47 million of long-term debt and the remainder with equity capital.

Completed Eloigne projects as of Dec. 31, 1999, are expected to generate tax credits of $78 million over the 10-year period 2000-2009. Tax credits recognized in 1999 as a result of these investments were approximately $9 million.

Ultra Power Technologies, Inc.

Ultra Power, formed in 1997, markets a proactive, non-destructive, power cable testing technology. Ultra Power has exclusive marketing rights to this technology throughout the United States and Canada. Ultra Power markets this service to utilities and commercial customers with underground cable.

Significant NRG Nonregulated Generation Projects Operating at Dec. 31, 1999

Generation Projects Operating	Location	Total Mw	NRG Ownership	Mw- Equity	Operator
Gladstone Power Station	Australia	1,680	37.50%	630	NRG
Loy Yang Power A	Australia	2,000	25.37%	507	NRG/CMS Generation
Crockett Cogeneration	USA	240	57.67%	138	NRG
Schkopau Power Station(1)	Germany	960	20.95%	200	PreussenElektra Kraftwerk A.G.
Cogeneration of America(2)	USA	575	20.00%	99	NRG
COBEE (Bolivian Power Co. Ltd.)	Bolivia	219	49.10%	108	COBEE
MIBRAG mbH	Germany	233	33.33%	78	MIBRAG
Energy Developments Limited	Australia	274	29.14%	79	Energy Development Limited
Scudder Latin American Power(3)	Latin America	772	6.63%	51	Stewart & Stevenson/Wartsila
Long Beach Generating	USA	530	50.00%	265	Southern California Edison
El Segundo Generating	USA	1,020	50.00%	510	Southern California Edison
Enfield Energy Centre	UK	396	25.00%	99	NRG/Indeck
Encina	USA	965	50.00%	483	San Diego Gas & Electric
San Diego Combustion Turbines	USA	253	50.00%	127	NRG
NRG Northeast Generating LLC	USA	6,980	100.00%	6,980	NRG

(1): Through a lease agreement, NRG has ownership of 200 Mw.
(2): Cogeneration Corp. of America owns various percentages of projects, making NRG's share of ownership 99 Mw.
(3): Scudder owns various percentages of projects, making NRG's share of ownership 51 Mw.

Summary of the Aggregate Financial Position of all of NSP's Nonregulated Businesses at Dec. 31:

(Thousands of dollars)	1999			1998
Equity investment by nonregulated businesses in unconsolidated projects
(Including undistributed earnings and capitalized development costs)
Australian projects	$	349 893		$	327 841
European projects		138 760			134 197
South American and Latin American projects		117 106			95 173
Affordable housing projects (U.S.)		53 338			45 411
U.S. power and energy projects		386 951			259 974
Other		1 200

Total equity investment in unconsolidated nonregulated projects	$	1 047 248		$	862 596
Nonregulated property of consolidated subsidiaries
(net of accumulated depreciation)—primarily U.S. projects		2 086 476			282 524
Notes receivable from unconsolidated projects, including current portion		67 163			110 886
Current assets		375 275			107 541
Other assets		207 306			126 110

Total assets of nonregulated businesses	$	3 783 468		$	1 489 657

Long-term debt, including current maturities	$	2 048 842		$	578 233
Short-term debt, including intercompany		379 438			126 236
Other current liabilities		159 679			39 183
Other liabilities		137 150			69 072

Total liabilities of nonregulated businesses		2 725 109			812 724
NSP's equity investment in nonregulated businesses		1 133 829			759 530
Cumulative currency translation adjustments		(75 470	)		(82 597	)

Total equity of nonregulated businesses		1 058 359			676 933

Total liabilities and equity of nonregulated businesses	$	3 783 468		$	1 489 657

ENVIRONMENTAL MATTERS

NSP 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 strives to comply with all applicable environmental laws.

NSP-Wisconsin has been named as one of three potentially responsible parties in connection with environmental contamination at a site in Ashland, Wis. NSP-Wisconsin has recorded a liability for an estimate of its share of the cost of remediating a portion of the Ashland site based on information available to date. For further discussion of the Ashland site see Note 14 to the Financial Statements under Item 8.

NSP 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 14 to the Financial Statements under Item 8.

With the acquisition of the NRG Northeast assets, NRG assumed certain liabilities for existing environmental conditions at the sites with the exception of off-site liabilities associated with the disposal of hazardous materials and certain other environmental liabilities.

Environmental site assessments have been prepared for all of the recently acquired NRG Northeast assets. The remediation activities at the Arthur Kill, Astoria and Somerset facilities are still in the study

phase. As such, remediation cost estimates are based on approaches that have yet to be approved by the regulatory agencies involved. Data from additional investigations performed at the Astoria Gas Turbines and the approach being taken at the Somerset Station may result in less costly remediation efforts than budgeted.

For the Connecticut facilities, NRG is planning to conduct additional studies to better quantify remedial needs. Such studies include the preparation of risk assessments to justify remedial actions proposed by NRG to the Connecticut Department of Environmental Protection and the U.S. Environmental Protection Agency (EPA).

Permits

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

Waste Disposal

Spent nuclear fuel storage and disposal issues are discussed in "Nuclear Power Plants—Operation and Waste Disposal" and in Notes 13 and 14 of Notes to Financial Statements under Item 8.

NSP has met or exceeded the state and federal removal and disposal requirements for polychlorinated biphenyl (PCB) equipment. NSP has removed nearly all known PCB capacitors from its distribution system, network transformers and equipment in power plants. NSP 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. NSP-Wisconsin's French Island facility will be subject to the EPA's small municipal waste combustor regulations. These have not yet been finalized but could result in installation of additional pollution control and monitoring equipment.

The Clean Air Act calls for reductions in emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx) from electric generating plants. NSP has expended significant amounts over the years to reduce SO2 emissions at its 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 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 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 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 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 MPCA a plan outlining steps the company will take as part of this voluntary effort. The plan is expected to be submitted in early 2000.

On Oct. 14, 1999, New York Gov. Pataki directed the Commissioner of the New York Department of Environment Conservation to require further reductions of SO2 emissions and NOx emissions from New York power plants, beyond what is required under current federal and state law. Under Gov. Pataki's directive, NOx emissions during the "non-ozone" season would be reduced to levels consistent with those currently mandated for the "ozone" season under the Ozone Transport Commission's Memorandum of Understanding. This additional reduction requirement would be phased in between 2003 and 2007. In addition, Gov. Pataki announced that he is ordering a reduction of S02 emissions by 50 percent beyond the requirements of the federal acid rain program. These reductions would also be phased in between 2003 and 2007. Compliance with these emission reduction requirements, if they become effective, could have a material impact on the operation of NRG's facilities located in New York.

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 cannot be determined.

As discussed in Note 14 to the Financial Statements under Item 8, NSP-Wisconsin challenged the EPA NOx emission regulations. In March 2000, the Court ruled that the EPA unlawfully included Wisconsin in the scope of the NOx rules. That decision releases NSP-Wisconsin from the new NOx rules.

Water Quality Monitoring

To comply with federal and state laws and state regulatory permit requirements, NSP 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, 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 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 also cannot predict whether future environmental regulations might result in significant reductions in generating capacity or efficiency or otherwise affect NSP's income, operations or facilities.

CAPITAL SPENDING AND FINANCING

NSP'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, and to fund investments in nonregulated businesses. NSP continually reassesses needs and, when necessary, appropriate changes are made in the capital expenditure program. Current year capital spending activity and future financing requirements and sources are discussed in the Management's Discussion and Analysis under Item 7.

NSP and Dairyland Power Cooperative have proposed building an electric transmission system between NSP's Chisago substation in eastern Minnesota and Dairyland's Apple River substation in northwestern Wisconsin in response to a need for additional reliability and capacity in both regions. During 1999, the PSCW granted permission to build the system. Approval from Minnesota regulators is pending. The Minnesota Department of Commerce (MDC) recommended against building the line as it is proposed, although they did acknowledge the need for more transmission capacity. Its recommendation will be considered by the Minnesota Environmental Quality Board (MEQB), which has the authority to approve or deny the project. NSP and Dairyland have responded to additional data requests from the MDC to be used in the regulatory proceedings in Minnesota. At this time, the administrative law judge is reviewing the case and parties are making their cases before him. A decision from the MEQB is expected in mid-2000.

In March 2000, NRG issued $250 million of 8.70 percent 20-year remarketable or redeemable securities through an unconsolidated grantor trust. The funds were subsequently converted to 160 million pound sterling and will be used to finance NRG's investment in the Killingholme power station in England.

In March 2000, NRG South Central Generating LLC, a subsidiary of NRG, issued $800 million of senior secured bonds in a two-part offering. The first tranche was for $500 million with a coupon of 8.962 percent and a maturity of 2016. The second tranche was for $300 million with a coupon of 9.479 percent and a maturity of 2024. The proceeds will be used to finance NRG's investment in the Cajun generating facilities.

EMPLOYEES AND EMPLOYEE BENEFITS

At year-end 1999, there were 9,098 full- and part-time NSP employees and 8,180 benefit employees. Approximately 3,204 employees are represented by five local International Brotherhood of Electric Workers (IBEW) labor unions.

Union Contract Extension

In 1999, NSP and the five IBEW local unions representing NSP 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.

Benefit Changes

NSP 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 Dec. 31, 1998, and for bargaining employees retiring after Dec. 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.

Item 2—Properties

NSP'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	1952-1960	462	1 383
	Gas
High Bridge
2 Units	Coal	1956-1959	267	1 187
Riverside
2 Units	Coal	1964-1987	380	2 155
Other	Various	Various	1919	1 773

NSP's electric generating facilities provided 74 percent of its kwh requirements in 1999. 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 NSP's major generating stations are located in Minnesota on land owned by NSP-Minnesota.

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

Voltage		Length (Pole Miles)
500kv		265
345kv		732
230kv		284
161kv		339
115kv		1,636
Less than 115kv		49,612

NSP also has approximately 284 transmission and distribution substations with capacities greater than 10,000 kilovoltamperes (kva) and approximately 288 with capacities less than 10,000 kva.

Manitoba Hydro, Minnesota Power Company and NSP completed the construction of a 500-kv transmission interconnection between Winnipeg, Manitoba, Canada, and the Minneapolis-St Paul, Minnesota, area in 1980. NSP has a contract with Manitoba Hydro for 500 Mw of firm power utilizing this transmission line. In addition, NSP 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 alternatives for serving the load growth.

NSP natural gas mains include approximately 117 miles of transmission mains and approximately 9,637 miles of distribution mains. In addition, Viking owns a 670-mile interstate natural gas pipeline serving portions of Minnesota, Wisconsin and North Dakota.

Virtually all of the utility plant of NSP-Minnesota and NSP-Wisconsin are subject to the lien of their first mortgage bond indentures pursuant to which they have issued first mortgage bonds.

For discussion and information concerning nonregulated properties, see "Nonregulated Subsidiaries" under Item 1, incorporated by reference.

Item 3—Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against NSP. 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 with the FERC, relating to transmission service curtailments. In March 1999, NSP and WE reached a settlement agreement, which was approved by the FERC on May 19, 1999. The settlement provides that NSP would not be liable to WE for transmission curtailments during 1998 and NSP would bear certain disputed transmission mitigation costs for 1998 and 1999. The settlement is not material.

On June 8, 1998, NSP 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 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's complaint. On May 20, 1999, NSP filed a notice of appeals with the Federal Circuit and on July 20, 1999, NSP filed its

initial brief on appeal. The Department of Justice, representing the United States, filed its initial brief on Oct. 29, 1999. No date has been set for oral argument. A decision is expected in mid-2000.

On Aug. 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 Jan. 31, 1998. NSP is named as nominal defendant because NSP has the contract with the DOE under which payments are made into the fund. On Dec. 23, 1999, the Court dismissed the class action suit.

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

For a discussion of other legal claims, see "Legal Claims" in Note 14 to the Financial Statements under Item 8, incorporated by reference. For a discussion of environmental proceedings, see "Environmental Matters" under Item 1, incorporated by reference. For a discussion of proceedings involving NSP's utility rates, see "Utility Regulation and Revenues" and "Gas Utility Operations" under Item 1, and "Rate Filings" under Item 7, all incorporated by reference.

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

None during the fourth quarter of 1999.

PART II

Item 5—Market for Registrant's Common Equity and Related Stockholder Matters

Quarterly Stock Data

NSP's common stock is listed on the New York Stock Exchange (NYSE), Chicago Stock Exchange and the Pacific Stock Exchange. Following are the reported high and low sales prices based on the NYSE Composite Transactions for the quarters of 1999 and 1998 and the dividends declared per share during those quarters. All per share amounts have been adjusted to reflect a two-for-one stock split effective June 1, 1998, for shareholders of record on May 18, 1998.

	1999				1998
	High	Low	Dividends		High	Low	Dividends
First Quarter	$27¹⁵/16	$23¹/16	$	0.3575	$29²⁵/32	$26¹/2	$	0.3525
Second Quarter	$26³/4	$22⁹/16	$	0.3625	$30⁷/32	$27¹¹/32	$	0.3575
Third Quarter	$24¹¹/16	$20¹⁵/16	$	0.3625	$29³/16	$25¹¹/16	$	0.3575
Fourth Quarter	$22¹¹/16	$19⁵/16	$	0.3625	$30¹³/16	$26³/16	$	0.3575

		1999			1998			1997			1996			1995
Shareholders of record at year-end			81 569			81 990			83 232			86 337			83 902
Book value per share at year-end		$	16.42		$	16.25		$	15.89		$	15.47		$	14.87

Shareholders of record as of March 15, 2000, were 82,135.

NSP's Restated Articles of Incorporation and First Mortgage Bond Trust Indenture provide for certain restrictions on the payment of cash dividends on common stock. At Dec. 31, 1999, the payment of cash dividends on common stock was not restricted except as described in Note 4 to the Financial Statements under Item 8.

Item 6—Selected Financial Data

(Dollars in millions except per share data)	1999		1998		1997		1996		1995
Utility operating revenues	$	2 869	$	2 819	$	2 734	$	2 654	$	2 569
Utility operating expenses	$	2 525	$	2 455	$	2 372	$	2 288	$	2 223
Net income	$	224	$	282	$	237	$	275	$	276
Earnings available for common stock	$	219	$	277	$	226	$	262	$	263
Average number of common shares outstanding (000's)		153 366		150 502		140 594		137 121		134 646
Average number of common and potentially dilutive shares outstanding (000's)		153 443		150 743		140 870		137 358		134 832
Earnings per Share-Basic	$	1.43	$	1.84	$	1.61	$	1.91	$	1.96
Earnings per Share-Diluted	$	1.43	$	1.84	$	1.61	$	1.91	$	1.95
Dividends declared per share	$	1.445	$	1.425	$	1.403	$	1.373	$	1.343
Total assets	$	9 768	$	7 396	$	7 144	$	6 637	$	6 229
Long-term debt	$	3 453	$	1 851	$	1 879	$	1 593	$	1 542
Ratio of earnings to fixed charges(a)		2.1		3.0		2.9		3.8		3.9

(a): excludes undistributed equity income and includes AFC

Item 7—Management's Discussion and Analysis

Northern States Power Company, a Minnesota corporation (NSP-Minnesota), has two significant subsidiaries: Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin), and NRG Energy, Inc., a Delaware corporation (NRG). NSP-Minnesota also has several other subsidiaries, including Viking Gas Transmission Company (Viking), Energy Masters International, Inc. (EMI), Eloigne Company (Eloigne), Seren Innovations, Inc. (Seren) and Ultra Power Technologies, Inc. (Ultra Power). NSP-Minnesota and its subsidiaries collectively are referred to as NSP.

FINANCIAL OBJECTIVES AND RESULTS

Because of several significant charges and adverse weather conditions (both are discussed later), 1999 earnings declined and NSP fell short of some of its financial objectives. This decline in earnings is not representative of NSP's continuing operational and financial strength.

Our earnings objective for 2000 is $1.95 per share, including build-out costs at Seren, which have reduced the projection by 15 cents per share. NRG is expected to contribute 80 cents per share, or about 40 percent of NSP's earnings. These projections assume NSP continues to own 100 percent of NRG and Seren.

In June 1999, NSP increased its dividend for the 25th consecutive year. The increase of 2 cents per share raised the dividend per share from $1.43 to $1.45 on an annual basis. At the time of the proposed merger to form Xcel Energy, the annual dividend is expected to be increased to $1.50 per share, equivalent to the current dividend of New Century Energies (NCE) adjusted for the 1.55 exchange ratio.

NSP's objective is to maintain continued financial strength with an AA rating for utility bonds. NSP-Minnesota's first mortgage bonds were rated:

•: AA- by Fitch IBCA

•: AA by Standard & Poors
•: Aa3 by Moody's Investors Service

The three rating agencies placed NSP's bond ratings under review upon announcement of its merger with NCE. These ratings and the review reflect the views of rating agencies, which can provide an explanation of the significance. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency. First mortgage bonds issued by NSP-Wisconsin carry comparable ratings.

BUSINESS STRATEGIES

NSP's mission is to be a recognized leader in the energy industry by increasing the value provided to our customers with energy-related products and services. We will utilize the skills and talents of our people to thrive in a dynamic and competitive energy environment that provides increased value for our customers and shareholders and significant growth opportunities for our company. NSP continues to move forward with its 10-Point Game Plan to achieve this mission.

Grow NRG—NRG's goal is to become a top independent power producer in each of its core markets: North America, Europe and Asia-Pacific. NRG expects to achieve this goal by profitably growing existing businesses and adding new businesses. NRG's asset acquisitions have enabled its earnings to grow from 16 cents per share in 1997 to 37 cents per share in 1999. NRG's long-term goal is to increase its earnings by an average of 25 percent per year. During 1999, NRG completed more than $1.6 billion of asset acquisitions, increasing its generation capability by more than 7,500 megawatts. During 2000, NRG expects to spend approximately $2.7 billion to acquire or develop more than 6,000 megawatts of generating facilities.

Position NSP's Generation Business for Long-Term Value—NSP's conventional plants include coal-fired, hydro, refuse-derived fuel, natural gas and oil-fired facilities. NSP will make strategic investments designed to enhance the value of these generating assets.

Create an Independent Nuclear Company—With increasing regulation and associated costs in the nuclear industry, NSP believes the best way to enhance NSP's nuclear assets is to combine our operations with other well-run nuclear plants and create a Nuclear Management Company. During 1999, NSP, Alliant Energy, Wisconsin Electric and Wisconsin Public Service Corporation formed a Nuclear Management Company (NMC) to provide services to member companies.

Expand Energy Marketing—To enhance NSP's position in the increasingly competitive electric market, NSP has expanded its wholesale energy marketing efforts by establishing an Energy Marketing function. Energy Marketing is responsible for meeting the requirements of NSP's retail and wholesale electric customers for low-cost energy, while optimizing margins from NSP's generation resources.

Provide for Independent Transmission Operations—To foster competition in the wholesale electricity market, the Federal Energy Regulatory Commission (FERC) requires the transmission portion of a utility's business to be functionally separate from the utility's generation facilities. The state of Wisconsin also calls for a separate transmission operating structure. During 1999, NSP joined the Midwest Independent System Operator (Midwest ISO) because it is the most effective means available to enhance the competitive market for wholesale electricity.

Expand NSP's Core Electric and Gas Distribution Business—To expand our core business, NSP will actively seek to acquire and merge with other energy companies. During 1999, NSP announced its plans to merge with NCE and form Xcel Energy. While NSP cannot guarantee the timing or receipt of the necessary regulatory approvals, NSP currently expects the merger to be completed by the middle of 2000.

Develop Seren—Seren provides broadband telecommunications services, including high-speed Internet access, telephone service and cable TV and soon will provide video-on-demand. Seren is expanding its broadband network in Minnesota, California and Colorado.

Grow Viking—NSP's goal is to continue the growth of Viking through pipeline expansion. During 1999, Viking completed a 5 percent capacity expansion. In addition, Viking, WICOR and CMS Energy announced plans to build a 147-mile natural gas pipeline to serve northern Illinois and southeastern Wisconsin.

Drive EMI to Profitability—EMI is narrowing its focus to concentrate on retrofitting and upgrading customer facilities for greater energy efficiency.

Manage NSP's Entire Business as a Portfolio—NSP will manage its collective businesses as a portfolio of assets with a focus on growth. NSP will acquire or divest businesses and assets if it will increase shareholder value. Pooling restrictions, associated with NSP's proposed merger with NCE, limit NSP's ability to divest assets for a period of time.

FINANCIAL REVIEW

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

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

•: general economic conditions, including their impact on capital expenditures
•: business conditions in the energy industry
•: competitive factors
•: unusual weather
•: changes in federal or state legislation
•: regulation
•: the higher risk associated with NSP's nonregulated businesses as compared with NSP's regulated business
•: currency translation and transaction adjustments
•: issues relating to Year 2000 remediation efforts
•: regulatory delays or conditions imposed by regulatory agencies in approving the proposed merger with NCE
•: the items described under "Factors Affecting Results of Operations"
•: the other risk factors listed from time to time by NSP in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to NSP's 1999 report on Form 10-K

Proposed Business Combination—On March 24, 1999, NSP and NCE agreed to merge and form a new entity, Xcel Energy. The merger requires approval or regulatory review by certain state and federal regulators. The merger is expected to be a tax-free, stock-for-stock exchange for shareholders of both companies and to be accounted for as a pooling of interests. At the time of the merger, Xcel Energy will register as a holding company.

The Xcel Energy board of directors will determine the dividend payment level of Xcel Energy. However, NSP anticipates that Xcel Energy will adopt an initial dividend equivalent to the current dividend of NCE. Based on the conversion ratio of 1.55 shares of Xcel common stock for each share of NCE stock, the pro forma dividend for Xcel Energy would currently be $1.50 per share annually.

For more discussion of this merger, see Note 15 to the Financial Statements. The following discussion and analysis is based on the financial condition and operations of NSP and does not reflect the potential effects of the proposed merger between NSP and NCE.

RESULTS OF OPERATIONS

1999 Compared with 1998 and 1997 NSP's earnings per share for the past three years were as follows:

	1999			1998		1997
	(Earnings per Share Diluted)
Regulated utility operations (excluding Primergy costs)	$	1.26		$	1.58	$	1.62
Nonregulated operations		0.22			0.26		0.11
CellNet investment write-down		(0.05	)

Subtotal excluding Primergy costs	$	1.43		$	1.84	$	1.73
Write-off of Primergy merger costs							(0.12	)

TOTAL	$	1.43		$	1.84	$	1.61

The combination of four significant one-time items accounted for a decline in 1999 earnings per share of 40 cents compared with 1998.

Conservation Incentive Recovery 1998—In 1999, the Minnesota Public Utilities Commission (MPUC) denied NSP recovery of 1998 lost margins, load management discounts and incentives associated with state-mandated programs for electric energy conservation. NSP recorded a $35 million charge based on this action, which reduced 1999 earnings by 14 cents per share. This charge represented a $32 million reduction in accrued revenue and a reduction of carrying charges. NSP may appeal the decision on 1998 conservation incentives.

Conservation Incentive Recovery 1999—At the end of 1999, the MPUC had not approved a conservation plan for 1999 or subsequent years. Based on the change in MPUC policy on conservation incentives and regulatory uncertainty, management decided not to accrue any conservation incentives for 1999. 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, 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. NSP estimates it could potentially earn $2 million-$3 million in 2000 for 1999 performance. NSP will file its performance report with the MPUC in the spring of 2000 and request approval of the appropriate amount based on final conservation program results for 1999. 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 13 cents per share from accrued conservation incentives. Including carrying charges, the reversal of 1998 conservation incentives reduced 1999 earnings by 14 cents per share, a decrease of 27 cents per share compared with incentive recovery levels in 1998. The earnings impacts in 1999 are non-cash accrual adjustments. NSP will make a filing with the MPUC in 2000 to address the cash impacts of conservation incentives collected in rates, including any overcollections for 1998 and 1999.

EMI Goodwill—NSP recorded a pretax charge of approximately $17 million, or about 8 cents per share, to write off all goodwill that was recorded by its subsidiary EMI for its acquisitions of Energy Masters Corporation in 1995 and Energy Solutions International in 1997. This charge reflects a revised business outlook based on recent levels of contract signings by EMI.

Loss on Marketable Securities—During 1999, NSP recorded pretax charges of approximately $14 million, or 5 cents per share, for a valuation write-down on its investment in the publicly traded common stock of CellNet Data Systems, Inc. In October 1999, CellNet announced it was experiencing financial difficulties and was contemplating restructuring its capital financing. In February 2000, CellNet filed for Chapter 11 bankruptcy protection. At Dec. 31,1999, the remaining value of NSP's investment in CellNet stock was approximately $1 million and Seren had approximately $5 million of intangible assets related to CellNet. Recovery of these assets is uncertain, pending the resolution of CellNet's financial difficulties.

REGULATED UTILITY OPERATING RESULTS

Electric Revenues—The following table summarizes the principal reasons for the electric revenue changes during the past two years:

	1999 vs. 1998			1998 vs. 1997
	(Millions of dollars)
Retail sales growth (excluding weather impact)	$	35		$	63
Estimated impact of weather on retail sales volume		(2	)		3
Sales for resale		25			47
Conservation incentive accrual adjustments		(78	)		4
Fuel cost recovery		47			19
Rate changes		5			2
Transmission and other		3			6

TOTAL REVENUE INCREASE	$	35		$	144

Electric sales growth for 1999 and 1998 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				1998 vs. 1997
	(Sales growth)
	Actual		Weather- Normalized		Actual		Weather- Normalized
Residential	2.4	%	2.5	%	3.4	%	3.7	%
Commercial and industrial	1.1	%	1.2	%	3.3	%	3.1	%
Total retail	1.5	%	1.6	%	3.3	%	3.3	%
Sales for resale	6.7	%	na		35.3	%	na
TOTAL ELECTRIC SALES	2.3	%	na		7.1	%	na

na = not applicable

Retail electric sales accounted for 93 percent of NSP's electric revenue in 1999 and 91 percent in 1998. Retail electric sales growth for 2000 is estimated to be 2.7 percent over 1999, or 2.1 percent on a weather-adjusted basis. Sales for resale volumes and revenues increased in 1999 and 1998 due to the expansion of NSP's wholesale energy marketing operations.

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

	1999			1998			1997
	(Millions of dollars)
Electric revenue	$	2 397		$	2 362		$	2 218
Fuel for electric generation		(319	)		(311	)		(310	)
Purchased and interchange power		(454	)		(378	)		(286	)

ELECTRIC MARGIN	$	1 624		$	1 673		$	1 622

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's service territory experienced extremely high temperatures, which drove customer usage to record levels. With NSP's power plants operating at maximum available capacity, market conditions forced NSP to purchase the power necessary to serve customer demand at very high costs. NSP's fuel clause billing adjustment process in Minnesota does not allow for the recovery of capacity charges above the levels reflected in base rates. In addition, NSP-Wisconsin does not have an automatic fuel clause to recover increased energy and capacity charges from customers. Without the ability to obtain full recovery, these unusually high energy and capacity costs reduced electric margin as shown below.

The following table summarizes the principal reasons for electric margin changes during the past two years:

	1999 vs. 1998			1998 vs. 1997
	(Millions of dollars)
Retail sales growth (excluding weather impact)	$	29		$	51
Estimated impact of weather on retail sales volume		(2	)		3
Sales for resale		7			11
Conservation incentive accrual adjustments		(78	)		4
Unrecovered demand, fuel and purchased power costs		(19	)		(14	)
Rate changes		5			2
Transmission and other		9			(6	)

TOTAL ELECTRIC MARGIN INCREASE (DECREASE)	$	(49	)	$	51

Gas Revenues—The following table summarizes the principal reasons for the gas revenue changes during the past two years:

	1999 vs. 1998			1998 vs. 1997
	(Millions of dollars)
Sales growth (excluding weather impact)	$	7		$	7
Estimated impact of weather on firm sales volume		20			(46	)
Purchased gas adjustment clause recovery		(11	)		(40	)
Rate changes		1			9
Black Mountain Gas Company acquisition					6
Transportation and other		(2	)		6

TOTAL REVENUE INCREASE (DECREASE)	$	15		$	(58	)

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's retail gas sales are categorized as firm (primarily heating customers) and interruptible (commercial/industrial customers with an alternate energy supply).

	1999 vs. 1998				1998 vs. 1997
	(Sales growth)
	Actual		Weather- Normalized		Actual		Weather- Normalized
Total firm	8.6	%	1.4	%	(13.1	)%	2.9	%
Interruptible	2.3	%	na		(10.4	)%	na
Total retail	6.9	%	na		(12.4	)%	na
Transportation and other	(11.8	)%	na		33.4	%	na
Viking (wholesale transportation)	(0.9	)%	na		2.8	%	na
TOTAL GAS SALES AND DELIVERY	1.1	%	na		(1.5	)%	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 15.1 percent higher than 1999 sales, or 2.2 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.

	1999			1998			1997
	(Millions of dollars)
Gas revenue	$	472		$	457		$	515
Cost of gas purchased and transported		(278	)		(267	)		(331	)

GAS MARGIN	$	194		$	190		$	184

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 following table summarizes the principal reasons for gas margin changes during the past two years:

	1999 vs. 1998			1998 vs. 1997
	(Millions of dollars)
Retail and transportation sales growth (excluding weather impact)	$	4		$	7
Estimated impact of weather on firm sales volume		6			(16	)
Rate changes		1			9
Black Mountain Gas Company acquisition					4
Other		(7	)		2

TOTAL GAS MARGIN INCREASE	$	4		$	6

Other Operation, Maintenance and Administrative and General—Expenses decreased in 1999 by $15.2 million, or 2.1 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.

Expenses increased in 1998 by $48.3 million, or 7.2 percent, compared with 1997. The higher costs in 1998 are primarily due to increased expenses associated with plant outages, nuclear regulatory costs, storm damage, Year 2000 remediation, energy marketing activities, customer growth and an insurance refund in 1997.

Depreciation and Amortization—Costs increased $17.5 million in 1999 and $12.3 million in 1998, primarily due to higher levels of depreciable plant, including new information systems and equipment with relatively short depreciable lives.

NONOPERATING UTILITY ITEMS

Utility Financing Costs—Interest costs for NSP's utility businesses were $128.5 million in 1999, $115.8 million in 1998 and $120.3 million in 1997. The 1999 increase is largely due to higher average short-term debt levels to support financing needs. The 1998 decrease is largely due to lower average short-term debt levels, partially offset by increased long-term debt levels. For more information, see the Statements of Capitalization.

Allowance for Funds Used During Construction (AFC)—AFC declined 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.

Primergy Merger Costs—In May 1997, NSP and Wisconsin Energy Corp. mutually terminated their plans to merge. NSP's earnings for 1997 include a pretax charge to nonoperating expense of $29 million, or 12 cents per share, to write off its cumulative merger-related costs incurred.

NONREGULATED BUSINESS RESULTS

A description of NSP's primary nonregulated businesses and their earnings contribution is summarized below.

•: NRG is involved in independent power production, commercial and industrial heating and cooling, and energy-related refuse-derived fuel production.
•: EMI is an energy services company.
•: Eloigne invests in affordable housing.
•: Seren provides broadband communication services.

CONTRIBUTION TO NSP'S EARNINGS PER SHARE

	1999			1998			1997
NRG	$	0.37		$	0.28		$	0.16
EMI		(0.13	)		(0.05	)		(0.08	)
Eloigne		0.05			0.04			0.03
Seren		(0.06	)		(0.02	)		(0.01	)
Other		(0.01	)		0.01			0.01

Subtotal—nonregulated subsidiaries	$	0.22		$	0.26		$	0.11
Write-down of investment in CellNet stock		(0.05	)

TOTAL	$	0.17		$	0.26		$	0.11

NRG—NRG's earnings increased for 1999, compared with 1998, primarily due to acquisitions of generating facilities in the Northeast region of the United States. During 1999, NRG recognized a gain of approximately 3 cents per share due to the partial sale of its interest in Cogeneration Corporation of America. Results for 1999 also reflected increased earnings from MIBRAG. These increased earnings were partially offset by the effects of cooler-than-normal weather in California, which reduced equity earnings at the El Segundo, Long Beach and Encina generating stations. In addition, earnings were decreased by costs related to project acquisitions and business development, and increased interest expenses. Also, equity earnings were affected by several other factors, including a currency transaction adjustment relating to the Kladno project and a decrease in earnings from NEO, NRG's landfill gas affiliate.

NRG's earnings increased in 1998, compared with 1997, primarily due to income from new projects. In addition, NEO generated higher levels of energy tax credits. Increased earnings were partially offset by higher interest costs. Also, NRG's earnings in 1998 were adversely affected by declines in the value of the Australian dollar and German deutsche mark in relation to the U.S. dollar. In 1997, NRG's investment in the Sunnyside project was written down by $9 million, or 4 cents per share.

In 1998, NRG sold one-half of its 50 percent interest in Enfield Energy Centre Ltd. for approximately $26 million, resulting in an after-tax gain of approximately $17 million. This gain increased 1998 earnings by approximately 11 cents per share. Also in 1998, NRG recorded a charge of approximately $22 million ($15 million after tax) to write down its investment in a 400-megawatt coal-fired power station in West Java, due to the political and economic instability in Indonesia. This write-down reduced 1998 earnings by approximately 10 cents per share.

Further information on NRG's financial results may be obtained from NRG's annual report on Form 10-K filed with the SEC.

EMI—EMI's losses for 1999 were greater than 1998, due to the write-off of goodwill associated with two acquisitions, as previously discussed. The write-off of goodwill reduced 1999 results by approximately 8 cents per share. EMI's losses for 1998 were lower than 1997, due to increased margins in 1998 and losses incurred by Enerval in 1997, a joint venture previously held by EMI. In 1998, EMI sold its interest in Enerval. EMI's investment in Enerval was written down in 1997.

Eloigne—Eloigne's earnings grew in 1999 and 1998 due to new investments in affordable housing projects.

Seren—Seren's build-out of its broadband communications network in St. Cloud, Minn., and initial construction in northern California resulted in losses for 1999 and 1998, consistent with Seren's business plan.

FACTORS AFFECTING RESULTS OF OPERATIONS

NSP's utility revenues depend on customer usage, which varies with weather conditions, general business conditions and the cost of energy services. Various regulatory agencies approve the prices for electric and gas service within their respective jurisdictions. In addition, NSP's nonregulated businesses are becoming a more significant factor in NSP's earnings. The historical and future trends of NSP's operating results have been and are expected to be affected by the following factors:

Regulation—NSP's utility rates are approved by the Federal Energy Regulatory Commission (FERC) and state regulatory commissions in Minnesota, North Dakota, South Dakota, Wisconsin, Arizona and Michigan. Rates are designed to recover plant investment, operating costs and an allowed return on investment. NSP requests changes in rates for utility services through filings with the governing commissions. The rates charged to retail customers in Wisconsin are reviewed and adjusted biennially. Because comprehensive rate changes are requested infrequently in Minnesota, NSP's primary jurisdiction, changes in operating costs can affect NSP's financial results. Except for Wisconsin electric operations, NSP'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. For Wisconsin electric operations, where cost-of-energy adjustment clauses are not used, the biennial retail rate review process and an interim fuel cost hearing process provide the opportunity for rate recovery of changes in electric fuel and purchased energy costs in lieu of a cost-of-energy adjustment 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 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's results of operations in the period the write-off is recorded. At Dec. 31, 1999, NSP reported on its balance sheet regulatory assets of approximately $136 million and regulatory liabilities of approximately $206 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 currently does not expect to write off any "stranded costs" unless market price levels change, or cost levels increase above market price levels. See Notes 1 and 9 to the Financial Statements for further discussion of regulatory deferrals.

Merger Settlement Agreements—In December 1999, NSP 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 proposed merger with NCE. Under the agreements, which contained substantially the same financial terms, NSP agreed to reduce its Minnesota electric rates by $10 million per year, or approximately 0.6 percent less than current levels, for 2001-2005. The agreements are subject to the approval of the MPUC and can be terminated in the event the merger does not proceed. Under the agreements, NSP's electric rates may not otherwise be increased through 2005, except under limited circumstances.

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

Competition—The Energy Policy Act of 1992 has been a catalyst for comprehensive and significant changes in the operation of electric utilities, including increased competition. The Act's reform of the Public Utility Holding Company Act of 1935 (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 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.

Some states have begun to allow retail customers to choose their electricity supplier, and many other states are considering retail access proposals. The Minnesota Legislature continues to study the issues, but has determined that further study is necessary before any action can be taken. The Public Service Commission of Wisconsin (PSCW) and Wisconsin Legislature have been focusing their efforts on improving electric reliability by requiring utility infrastructure improvements prior to addressing customer choice. The Michigan Public Service Commission has approved voluntary plans that began offering retail customers a choice of suppliers in selected markets in 1998. The Michigan Legislature is considering legislation to allow customer choice for all customers by 2002. The timing of regulatory and legislative actions regarding restructuring and their impact on NSP cannot be predicted at this time and may be significant.

Transmission Operations—During 1999, NSP 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. Recent developments include:

•: 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's service area to Pennsylvania and south through Illinois and Kentucky. NSP 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.
•: Wisconsin state law requires the PSCW to order a public utility that owns transmission facilities in Wisconsin to transfer control of its transmission facilities to an ISO or divest its interest in its transmission facilities to an Independent Transmission Company (ITC) by June 30, 2000. It is expected that during 2000 the PSCW will approve NSP-Wisconsin's request to join the Midwest ISO and certify that NSP-Wisconsin's joining of the Midwest ISO will satisfy the requirements of this Wisconsin law.

Nuclear Management Company (NMC)—As part of its game plan, NSP announced its intention to form an independent nuclear management company. Recent developments include:

•: During 1999, NSP, 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, 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'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.

Used Nuclear Fuel Storage and Disposal—In 1994, NSP received legislative authorization from the state of Minnesota to use 17 casks for temporary spent-fuel storage at NSP's Prairie Island nuclear generating facility. NSP has determined that 17 casks will allow operation of the facility until 2007. NSP had loaded nine of the casks as of Dec. 31, 1999. As a condition of the authorization, the Minnesota Legislature established several resource commitments for NSP, including wind and biomass generation sources as well as other requirements. NSP is complying with these requirements, as discussed in Note 14 to the Financial Statements.

NSP and other utilities have an ongoing dispute with the U.S. Department of Energy (DOE) regarding the DOE's statutory and contractual obligations to provide permanent storage and disposal facilities for nuclear fuel by Jan. 31, 1998, as required by the Nuclear Waste Policy Act of 1982. See Note 13 to the Financial Statements for more information.

Year 2000 (Y2K)—NSP's Y2K program covered not only NSP's 2,000 computer applications, consisting of about 75,000 programs and totaling more than 30 million lines of code, but also the thousands of hardware and embedded system components in use throughout NSP. Although it appears that NSP successfully transitioned into the year 2000 with no Y2K disruptions to customers or to internal operations, there are no guarantees that a Y2K-related problem will not surface at a later date. NSP is not presently aware of any such situations; however, occurrences of this type could adversely affect NSP's business, operating results or financial condition.

NSP has spent approximately $22 million for Y2K efforts, from 1996-1999. This includes $9 million in 1999. These costs have been expensed as incurred, except for a small portion deferred for approved rate recovery.

Environmental Matters—NSP incurs several types of environmental costs, including nuclear plant decommissioning, storage and ultimate disposal of spent nuclear fuel, disposal of hazardous materials and wastes, remediation of contaminated sites and monitoring of discharges into the environment. Because of greater environmental awareness and increasingly stringent regulation, NSP has experienced increasing environmental costs. This trend has caused, and may continue to cause, slightly higher operating expenses and capital expenditures for environmental compliance. In addition, NRG's recent acquisition of generation facilities will tend to increase nonutility costs for environmental compliance.

In addition to nuclear decommissioning and spent nuclear fuel disposal expenses, costs charged to NSP's operating expenses for environmental monitoring and disposal of hazardous materials and wastes were approximately:

•: $32 million in 1999
•: $32 million in 1998
•: $31 million in 1997

NSP's utility operations expect to spend approximately $35 million per year for 2000-2004. However, the precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are currently unknown.

Capital expenditures on environmental improvements at its utility facilities, which include the costs of constructing spent nuclear fuel storage casks, were approximately:

•: $39 million in 1999
•: $21 million in 1998
•: $19 million in 1997

NSP expects to incur approximately $24 million in capital expenditures for compliance with environmental regulations in 2000 and approximately $74 million for 2000-2004. In addition, NRG expects to incur approximately $44 million in capital expenditures for environmental compliance for 2000-2004. See Notes 13 and 14 to the Financial Statements for further discussion of NSP's environmental contingencies.

Weather—NSP's earnings can be 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 reduces electric and gas sales. The following summarizes the estimated impact on NSP's earnings due to temperature variations from historical averages.

•: Weather in 1999 decreased earnings by an estimated 8 cents per share.
•: Weather in 1998 decreased earnings by an estimated 11 cents per share.
•: Weather in 1997 decreased earnings by an estimated 6 cents per share.

Impact of Nonregulated Investments—A significant portion of NSP's earnings comes from nonregulated operations. NSP expects to continue investing in nonregulated projects, including domestic and international power production projects through NRG and broadband communications systems through Seren. NSP's nonregulated businesses may carry a higher level of risk than NSP's traditional utility businesses due to a number of factors, including:

•: competition, operating risks, dependence on certain suppliers and customers, and domestic and foreign environmental and energy regulations;
•: partnership and government actions and foreign government, political, economic and currency risks; and
•: development risks, including uncertainties prior to final legal closing.

Some of NRG's project investments (as listed in Note 10 to the Financial Statements) consist of minority interests, which may limit NRG's financial risk, but also limit NRG's ability to control the development or operation of the projects. In addition, significant expenses may be incurred for projects pursued by NRG that do not materialize. The aggregate effect of these factors creates the potential for volatility in the nonregulated component of NSP's earnings. Accordingly, the historical operating results of NSP's nonregulated businesses may not necessarily be indicative of future operating results.

Use of Derivatives and Market Risk—NSP uses derivative financial instruments to mitigate the impact of changes in foreign currency exchange rates on NRG's international project cash flows, natural gas, electricity and fuel prices on margins and interest rates on the cost of borrowing. See Notes 1 and 11 to the Financial Statements for further discussion of NSP's financial instruments and derivatives.

The fair value of NRG's interest rate hedging contracts is sensitive to changes in interest rates. As of Dec. 31, 1999, a 10 percent decrease in interest rates from prevailing market rates would decrease the market value of NRG's interest rate hedging contracts by approximately $28 million. Conversely, a 10 percent increase in interest rates from the prevailing market rates would increase the market value by approximately $26 million.

NRG has an investment in the Kladno project in the Czech Republic. Statement of Financial Accounting Standard (SFAS) No. 52 requires foreign currency gains and losses to flow through the income statement if settlement of an obligation is in a currency other than the local currency of the entity. A portion of the Kladno project debt is in non-local currency (U.S. dollars and German deutsche marks). As of Dec. 31, 1999, if the value of the Czech koruna decreased by 10 percent in relation to the U.S. dollar and the German deutsche mark, NRG would have recorded a $5 million loss (after tax) on the currency transaction adjustment. If the value of the Czech koruna increased by 10 percent, NRG would have recorded a $5 million gain (after tax) on the currency transaction adjustment.

In February 1999, EMI transferred its natural gas supply and marketing function to NSP's Energy Marketing division. Sales commitments and natural gas futures and forward contracts that EMI entered into prior to the transfer remain the contractual responsibility of EMI. As of Dec. 31, 1999, EMI had natural gas forward and futures contracts in the notional amount of less than $1 million. These contracts will expire during 2000 and EMI will have no further derivative activity. EMI's market risk due to changes in market prices of natural gas forward and futures contracts is immaterial.

NSP'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's financial results. Any changes in the values of these futures contracts would be offset by a change in the underlying commodities being hedged.

NRG's power marketing subsidiary is exposed to the risk of changes in market prices of fuel oil, natural gas and electricity. To manage exposure to this volatility, NRG uses a variety of energy contracts, including options, swaps and forward contracts. As of Dec. 31, 1999, a 10 percent increase in fuel oil, natural gas and electricity forward prices would result in a gain on these contracts of approximately $12 million. Conversely, a 10 percent decrease in fuel oil, natural gas and electricity forward prices would result in a loss on these contracts of approximately $12 million. These hypothetical gains and losses on energy forward contracts would be offset by the gains and losses on the underlying commodities being hedged.

Accounting Changes—The Financial Accounting Standards Board (FASB) has proposed new accounting standards that would require the full accrual of nuclear plant decommissioning and certain other site exit obligations. Material adjustments to NSP's balance sheet would occur upon implementation of the FASB's proposal, which would be no earlier than 2002. However, the effects of regulation are expected to minimize or eliminate any impact on operating expenses and earnings from this future accounting change. For further discussion of the expected impact of this change, see Note 13 to the Financial Statements.

In June 1998, the FASB issued 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. NSP plans to adopt this standard in 2001, as required. NSP has not yet determined the potential impact of implementing this statement.

Inflation—Inflation at its current level is not expected to materially affect NSP's prices or returns to shareholders.

LIQUIDITY AND CAPITAL RESOURCES

1999 Financing Requirements—NSP'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 and to fund equity commitments or other investments in nonregulated businesses. In 1999:

•: Total utility capital expenditures were $462 million. Of that amount, $367 million related to replacements and improvements of NSP's electric system and nuclear fuel, and $67 million involved construction of natural gas facilities.
•: NSP companies (mainly NRG) invested approximately $1.9 billion for equity interests in and loans to nonregulated projects for the acquisition of generating assets and for additions to nonregulated property.

1999 Financing Activity—During 1999, NSP'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'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. NSP's goal for its pretax interest coverage ratio for utility operations is 3.5-5.0. The utility pretax interest coverage ratio, excluding AFC, was 3.2 in 1999, 3.8 in 1998 and 3.6 in 1997. Internally generated funds from utility operations could have provided financing for approximately 80 percent of NSP's utility capital expenditures for 1999 and approximately 95 percent of the $2.0 billion in utility capital expenditures incurred from 1995-1999. The pretax interest coverage ratio, excluding AFC, for all NSP operations was 2.1 in 1999, 2.9 in 1998 and 2.8 in 1997.
•: External financing—NSP's short-term debt availability and usage is described in Note 2 to the Financial Statements. In general, short-term borrowings are used to provide temporary financing, mainly for NSP-Minnesota and NRG, utility capital expenditures, nonregulated projects and other short-term cash needs. NSP's long-term debt and capital stock activity are shown on the Statements of Capitalization and Stockholders' Equity. These sources are used to provide permanent financing for both regulated and nonregulated business activities.

The 1999 nonregulated asset acquisitions, property additions and equity investments by NSP's subsidiaries were primarily financed by the issuance of subsidiary debt and equity contributions from NSP. Project debt associated with some nonregulated investments is not reflected in NSP's balance sheet because the equity method of accounting is used for such investments as discussed in Note 10 to the Financial Statements.

Future Financing Requirements—NSP currently estimates that its utility capital expenditures will be $490 million in 2000 and $2.3 billion for 2000-2004. Of the 2000 amount, approximately $410 million is scheduled for electric utility facilities and approximately $50 million for natural gas facilities. In addition to

utility capital expenditures, expected financing requirements for 2000-2004 include approximately $1 billion to retire long-term debt and fund principal maturities.

NSP subsidiaries expect to invest significant amounts in nonregulated projects in the future. Financing requirements for nonregulated project investments will vary depending on the success, timing and level of involvement in projects currently under consideration.

•: NRG expects to invest approximately $2.7 billion in 2000 and approximately $4.7 billion for 2000-2004 for nonregulated projects and property, which include acquisitions and project investments. NRG's capital requirements may vary significantly. NRG's capital requirements for 2000 reflect expected acquisitions of existing generation facilities, including Cajun, Killingholme A and the Conectiv fossil assets. A significant portion of NRG's capital requirements is expected to be financed by project-secured debt. In addition, NRG may issue a limited amount of equity financing to third parties for funding a portion of the capital requirements.
•: Seren expects to spend approximately $180 million during 2000, which reflects the build-out of its broadband communications network in Northern California. Seren is evaluating its financing options, including equity financing to third parties and project-secured debt. Seren's capital requirements for 2001-2004 may vary significantly depending on the success of development efforts under way.

NSP and its subsidiaries continue to evaluate opportunities to enhance shareholder returns and achieve long-term financial objectives through investments in projects or acquisitions of existing businesses. These investments could cause significant changes to the capital requirement estimates for nonregulated projects and property. Long-term financing may be required for such investments.

NSP 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 expects to meet future financing requirements by periodically issuing long-term debt, short-term debt, common stock and preferred securities to maintain desired capitalization ratios. Over the long term, NSP's equity investments in and acquisitions of nonregulated projects are expected to be financed at the nonregulated subsidiary level from internally generated funds or the issuance of subsidiary debt. Financing requirements for the nonregulated projects, in excess of equity contributions from partners, are expected to be fulfilled through project or subsidiary debt. Decommissioning expenses not funded by an external trust will be financed through a combination of internally generated funds, long-term debt and common stock.

The following summarizes the financing sources expected to be available to NSP in the near future:

•: Internal funds—Internally generated funds from utility operations are expected to equal approximately 85 percent of anticipated utility capital expenditures for 2000 and approximately 95 percent of the anticipated utility capital expenditures for 2000-2004. Because NRG has been reinvesting foreign cash flows in operations outside the United States, the equity income from foreign investments is not fully available to provide operating cash flows for domestic cash requirements such as payment of NSP dividends, domestic capital expenditures and domestic debt service.
•: Short-term debt—NSP has received regulatory approval for up to approximately $1.5 billion in short-term borrowing levels. NSP credit lines (as discussed in Note 2 to the Financial Statements) make short-term financing available in the form of bank loans, letters of credit and support for commercial paper.
•: Utility long-term debt—NSP-Minnesota's and NSP-Wisconsin's first mortgage indentures limit the amount of first mortgage bonds that may be issued. The MPUC and the PSCW have jurisdiction

over securities issuance. At Dec. 31, 1999, with an assumed interest rate of 7.75 percent, NSP-Minnesota could have issued about $1.9 billion of additional first mortgage bonds under its indenture and NSP-Wisconsin could have issued about $320 million of additional first mortgage bonds under its indenture. NSP has $150 million of unissued bonds remaining from its $400 million universal shelf registration filed with the SEC in November 1998 and $50 million of unissued first mortgage bonds remaining from its shelf registration filed in October 1995. In addition, NSP-Minnesota is planning on filing a $400 million universal debt shelf registration during the first half of 2000. During 1999, NSP-Wisconsin filed a shelf registration with the SEC to issue up to $80 million of long-term debt. NSP-Wisconsin currently expects to issue between $50 million and $80 million of unsecured long-term debt during 2000, primarily to reduce short-term debt levels.

•: NRG debt—In December 1999, NRG filed a shelf registration with the SEC to issue up to $500 million of unsecured debt. NRG expects to issue debt under this shelf during 2000 for general corporate purposes, which may include financing development and construction of new facilities, additions to working capital and financing capital expenditures and pending or potential acquisitions. In addition to NRG corporate debt, NRG Northeast Generating LLC (N.E. Generating), a wholly owned subsidiary of NRG, issued $750 million of bonds in February 2000 to pay down short-term borrowings and reduce NRG's corporate debt issued to fund N.E. Generating (see Note 2).
•: Common stock—NSP's Articles of Incorporation authorize an additional 194.3 million shares of common stock in excess of shares issued at Dec. 31, 1999. In 1999, NSP filed registration statements with the SEC to allow for the sale of up to 1.9 million shares of newly issued common stock under NSP's Dividend Reinvestment and Stock Purchase Program (DRSPP) and Executive Long-Term Incentive Award Stock Plan. NSP plans to issue new shares for its DRSPP, Employee Stock Ownership Plan (ESOP) and Executive Long-Term Incentive Award Stock Plan in 2000. NSP filed its proposed 2000 Capital Structure and Financing Plan with the MPUC in November 1999. In its filing, NSP proposed that if the completion of its merger with NCE is timed as currently anticipated, NSP will be recapitalized as a subsidiary of Xcel Energy. If completion of the merger appears to be delayed, NSP may issue equity or an equity-related security in the first half of 2000.
•: Preferred stock—NSP's Articles of Incorporation authorize the maximum amount of preferred stock that may be issued. Under these provisions, NSP could have issued all $595 million of its remaining authorized, but unissued, preferred stock at Dec. 31, 1999, and remained in compliance with all interest and dividend coverage requirements.

Item 7A—Quantitative and Qualitative Disclosures About Market Risk

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

Item 8—Financial Statements and Supplementary Data

See Item 14(a)-1 in Part IV for index of financial statements included herein.

See Note 16 of Notes to Financial Statements for summarized quarterly financial data.

REPORT OF INDEPENDENT ACCOUNTANTS

To the Shareholders of
Northern States Power Company:

In our opinion, the accompanying consolidated balance sheets and statements of capitalization and the related consolidated statements of income, of common stockholders' equity and of cash flows present fairly, in all material respects, the financial position of Northern States Power Company (NSP), a Minnesota corporation, and its subsidiaries at Dec. 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended Dec. 31, 1999, in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of NSP'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 2, which is as of February 22, 2000

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31
	1999			1998			1997
	(Thousands of dollars, except per share data)
UTILITY OPERATING REVENUES
Electric: Retail	$	2 169 296		$	2 152 221		$	2 054 473
Sales for resale and other		227 800			210 130			164 077
Gas		471 915			456 823			515 196

Total		2 869 011			2 819 174			2 733 746

UTILITY OPERATING EXPENSES
Fuel for electric generation		319 193			311 368			309 999
Purchased and interchange power		454 487			377 907			286 239
Cost of gas purchased and transported		278 240			267 050			331 296
Other operation		401 968			392 054			368 545
Maintenance		178 594			181 066			164 542
Administrative and general		127 427			150 078			141 802
Conservation and energy management		60 180			71 134			70 939
Depreciation and amortization		355 704			338 225			325 880
Property and general taxes		222 446			220 620			227 893
Income taxes		127 293			145 383			144 855

Total		2 525 532			2 454 885			2 371 990

Utility operating income		343 479			364 289			361 756

OTHER INCOME (EXPENSE)
Income from nonregulated businesses—before interest and taxes		79 439			51 171			12 078
Allowance for funds used during construction—equity		162			8 509			6 401
Write-down of investment in CellNet stock		(14 063	)
Primergy merger costs								(29 005	)
Other utility income (deductions)—net		(9 483	)		(3 697	)		(2 886	)
Income taxes on nonregulated operations and nonoperating items—benefit		61 011			40 588			48 145

Total		117 066			96 571			34 733

Income before financing costs		460 545			460 860			396 489

FINANCING COSTS
Interest on utility long-term debt		102 843			104 171			101 250
Other utility interest and amortization		25 677			11 612			19 063
Nonregulated interest and amortization		97 854			54 261			34 627
Allowance for funds used during construction—debt		(5 915	)		(7 307	)		(10 208	)

Total interest charges		220 459			162 737			144 732
Distributions on redeemable preferred securities of subsidiary trust		15 750			15 750			14 437

Total financing costs		236 209			178 487			159 169

NET INCOME		224 336			282 373			237 320
Preferred stock dividends and redemption premiums		5 292			5 548			11 071

EARNINGS AVAILABLE FOR COMMON STOCK	$	219 044		$	276 825		$	226 249

Average number of common shares outstanding (000s)		153 366			150 502			140 594
Average number of common and potentially dilutive shares outstanding (000s)		153 443			150 743			140 870
EARNINGS PER AVERAGE COMMON SHARE—BASIC	$	1.43		$	1.84		$	1.61
EARNINGS PER AVERAGE COMMON SHARE—DILUTED	$	1.43		$	1.84		$	1.61
Common dividends declared per share	$	1.445		$	1.425		$	1.403

See Notes to Financial Statements

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31
	1999			1998			1997
	(Thousands of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	224 336		$	282 373		$	237 320
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization		423 807			379 397			358 928
Nuclear fuel amortization		50 056			43 816			40 015
Deferred income taxes		(18 907	)		(1 017	)		(5 902	)
Deferred investment tax credits recognized		(9 417	)		(9 432	)		(10 061	)
Allowance for funds used during construction—equity		(162	)		(8 509	)		(6 401	)
Undistributed equity in earnings of unconsolidated affiliates		(27 956	)		(22 753	)		(5 364	)
Conservation incentive adjustments—noncash		71 348
Write-downs of EMI goodwill and CellNet investment		31 346
Write-off of prior year Primergy merger costs								25 289
Cash provided by (used for) changes in certain working capital items (see below)		(80 649	)		(13 673	)		36 117
Cash provided by changes in other assets and liabilities		17 348			51 863			19 844

NET CASH PROVIDED BY OPERATING ACTIVITIES		681 150			702 065			689 785

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures:
Nonregulated property additions and asset acquisitions		(1 698 414	)		(44 918	)		(195 528	)
Utility plant additions (including nuclear fuel)		(462 054	)		(411 113	)		(396 605	)
Increase (decrease) in construction payables		(2 604	)		5 270			2 563
Allowance for funds used during construction—equity		162			8 509			6 401
Investment in external decommissioning fund		(39 183	)		(41 360	)		(41 261	)
Equity investments, loans and deposits for nonregulated projects		(176 207	)		(234 214	)		(395 495	)
Collection of loans made to nonregulated projects		81 440			109 530			87 128
Other investments—net		(16 545	)		1 307			(15 692	)

NET CASH USED FOR INVESTING ACTIVITIES		(2 313 405	)		(606 989	)		(948 489	)

CASH FLOWS FROM FINANCING ACTIVITIES
Change in short-term debt—net issuances (repayments)		1 205 894			(20 522	)		(108 023	)
Proceeds from issuance of long-term debt—net		859 718			290 626			299 779
Repayment of long-term debt, including reacquisition premiums		(249 371	)		(135 183	)		(141 681	)
Proceeds from issuance of preferred securities—net								193 315
Proceeds from issuance of common stock—net		55 127			72 348			267 965
Redemption of preferred stock, including reacquisition premiums					(95 000	)		(41 278	)
Dividends paid		(225 509	)		(219 746	)		(207 726	)

NET CASH PROVIDED BY (USED FOR) FINANCING ACTIVITIES		1 645 859			(107 477	)		262 351

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		13 604			(12 401	)		3 647
Cash and cash equivalents at beginning of period		42 364			54 765			51 118
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	55 968		$	42 364		$	54 765
CASH PROVIDED BY (USED FOR) CHANGES IN CERTAIN WORKING CAPITAL ITEMS
Customer accounts receivable and unbilled utility revenues	$	(106 692	)	$	(1 583	)	$	47 745
Materials and supplies inventories		(22 228	)		(5 385	)		(8 547	)
Payables and accrued liabilities (excluding construction payables)		73 136			7 845			(7 342	)
Other		(24 865	)		(14 550	)		4 261

Net	$	(80 649	)	$	(13 673	)	$	36 117

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the year for:
Interest (net of amount capitalized)	$	201 276		$	148 275		$	144 062
Income taxes (net of refunds received)	$	65 121		$	74 005		$	113 009

See Notes to Financial Statements

CONSOLIDATED BALANCE SHEETS

	December 31
	1999			1998
	(Thousands of dollars)
ASSETS
UTILITY PLANT
Electric—including construction work in progress: 1999, $119,944; 1998, $120,095	$	7 430 686		$	7 199 843
Gas		952 131			884 182
Other		375 058			365 101

Total		8 757 875			8 449 126
Accumulated provision for depreciation		(4 409 151	)		(4 155 641	)
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		4 451 451			4 395 234

CURRENT ASSETS
Cash and cash equivalents		55 968			42 364
Customer accounts receivable—net of accumulated provisions for uncollectible accounts: 1999, $8,442; 1998, $5,176		370 270			253 559
Unbilled utility revenues		144 261			139 098
Other receivables		58 680			105 116
Materials and supplies inventories—at average cost:
Fuel		59 600			58 806
Other		231 503			110 267
Prepayments and other		113 524			44 855

Total current assets		1 033 806			754 065

OTHER ASSETS
Nonregulated property—net of accumulated depreciation: 1999, $203,767; 1998, $122,445		2 086 476			282 524
Equity investments in nonregulated projects		1 047 248			862 596
External decommissioning fund and other investments		561 682			479 402
Regulatory assets		248 127			331 940
Notes receivable from nonregulated projects		66 876			106 427
Long-term prepayments, deferred charges and receivables		158 096			88 194
Intangible assets—net of accumulated amortization		113 969			95 915

Total other assets		4 282 474			2 246 998

TOTAL	$	9 767 731		$	7 396 297

LIABILITIES AND EQUITY
CAPITALIZATION (SEE CONSOLIDATED STATEMENTS OF CAPITALIZATION)
Common stockholders' equity	$	2 557 530	$	2 481 246
Preferred stockholders' equity		105 340		105 340
Mandatorily redeemable preferred securities of subsidiary trust		200 000		200 000
Long-term debt		3 453 364		1 851 146

Total capitalization		6 316 234		4 637 732

CURRENT LIABILITIES
Long-term debt due within one year		153 231		227 600
Other long-term debt potentially due within one year		141 600		141 600
Short-term debt—utility		420 443		114 273
Short-term debt—nonregulated		378 716		125 557
Accounts payable		321 382		271 799
Taxes accrued		172 059		170 274
Interest accrued		49 327		38 836
Dividends payable on common and preferred stocks		57 523		55 650
Accrued payroll, vacation and other		131 855		86 673

Total current liabilities		1 826 136		1 232 262

OTHER LIABILITIES
Deferred income taxes		811 638		814 983
Deferred investment tax credits		118 582		128 444
Regulatory liabilities		461 569		372 239
Postretirement and other benefit obligations		143 905		129 514
Other long-term obligations and deferred income		89 667		81 123

Total other liabilities		1 625 361		1 526 303

COMMITMENTS AND CONTINGENT LIABILITIES (SEE NOTES 13 AND 14)

TOTAL	$	9 767 731	$	7 396 297

See Notes to Financial Statements

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY

	Par Value		Premium		Retained Earnings			Shares Held by ESOP			Accumulated Other Comprehensive Income			Total Stockholders' Equity
	(Thousands of dollars)
BALANCE AT DEC. 31, 1996	$	345 318	$	466 060	$	1 340 799		$	(19 091	)	$	2 794		$	2 135 880

Net income						237 320									237 320
Currency translation adjustments												(65 681	)		(65 681	)

Comprehensive income for 1997															171 639
Dividends declared:
Cumulative preferred stock						(9 923	)								(9 923	)
Common stock						(202 173	)								(202 173	)
Premium on redeemed preferred stock						(1 148	)								(1 148	)
Issuances of common stock—net		27 774		240 112											267 886
Tax benefit from stock options exercised				1 009											1 009
Repayment of ESOP loan (a)									8 558						8 558

BALANCE AT DEC. 31, 1997	$	373 092	$	707 181	$	1 364 875		$	(10 533	)	$	(62 887	)	$	2 371 728

Net income						282 373									282 373
Unrealized loss from marketable securities, net of tax of $4,417												(6 416	)		(6 416	)
Currency translation adjustments												(19 711	)		(19 711	)

Comprehensive income for 1998															256 246
Dividends declared:
Cumulative preferred stock						(5 548	)								(5 548	)
Common stock						(215 069	)								(215 069	)
Issuances of common stock—net		8 650		66 294											74 944
Pooling of interests business combinations						6 065									6 065
Tax benefit from stock options exercised				850											850
Loan to ESOP to purchase shares (a)									(15 000	)					(15 000	)
Repayment of ESOP loan (a)									7 030						7 030

BALANCE AT DEC. 31, 1998	$	381 742	$	774 325	$	1 432 696		$	(18 503	)	$	(89 014	)	$	2 481 246

Net income						224 336									224 336
Recognition of unrealized loss from marketable securities, net of tax of $4,417												6 416			6 416
Currency translation adjustments												7 128			7 128

Comprehensive income for 1999															237 880
Dividends declared:
Cumulative preferred stock						(5 292	)								(5 292	)
Common stock						(222 092	)								(222 092	)
Issuances of common stock—net		7 582		46 652											54 234
Pooling of interests business combination						4 599									4 599
Tax benefit from stock options exercised				58											58
Repayment of ESOP loan (a)									6 897						6 897

BALANCE AT DEC. 31, 1999	$	389 324	$	821 035	$	1 434 247		$	(11 606	)	$	(75 470	)	$	2 557 530

(a) Did not affect NSP cash flows
See Notes to Financial Statements

CONSOLIDATED STATEMENTS OF CAPITALIZATION

	December 31
	1999			1998
	(Thousands of dollars)
COMMON STOCKHOLDERS' EQUITY
Common stock—authorized 350,000,000 shares of $2.50 par value; issued shares: 1999, 155,729,663; 1998, 152,696,971	$	389 324		$	381 742
Premium on common stock		821 035			774 325
Retained earnings		1 434 247			1 432 696
Leveraged common stock held by Employee Stock Ownership Plan (ESOP)—shares at cost: 1999, 392,325; 1998, 641,884		(11 606	)		(18 503	)
Accumulated other comprehensive income		(75 470	)		(89 014	)

TOTAL COMMON STOCKHOLDERS' EQUITY	$	2 557 530		$	2 481 246

CUMULATIVE PREFERRED STOCK—authorized 7,000,000 shares of $100 par value; outstanding shares: 1999 and 1998, 1,050,000
NSP-Minnesota
$3.60 series, 275,000 shares	$	27 500		$	27 500
4.08 series, 150,000 shares		15 000			15 000
4.10 series, 175,000 shares		17 500			17 500
4.11 series, 200,000 shares		20 000			20 000
4.16 series, 100,000 shares		10 000			10 000
4.56 series, 150,000 shares		15 000			15 000

Total		105 000			105 000
Premium on preferred stock		340			340

TOTAL PREFERRED STOCKHOLDERS' EQUITY	$	105 340		$	105 340

MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST—holding as its sole asset junior subordinated deferrable debentures of NSP-Minnesota 7⁷/8% series, 8,000,000 shares due Jan. 31, 2037 (See Note 8)	$	200 000		$	200 000

LONG-TERM DEBT
First Mortgage Bonds—NSP-Minnesota
Series due:
Feb. 1, 1999, 5¹/2%				$	200 000
Dec. 1, 2000, 5³/4%	$	100 000			100 000
Oct. 1, 2001, 7⁷/8%		150 000			150 000
April 1, 2003, 6³/8%		80 000			80 000
Dec. 1, 2005, 6¹/8%		70 000			70 000
Dec. 1, 1999-2006, 6.00%—6.75%					16 900	*
Dec. 1, 1999-2006, 3.50%—4.10%		15 170	*
March 1, 2011, Variable Rate		13 700	**		13 700	**
July 1, 2025, 7¹/8%		250 000			250 000
April 1, 2007, 6.80%		60 000	**		60 000	**
March 1, 2019, Variable Rate		27 900	**		27 900	**
Sept. 1, 2019, Variable Rate		100 000	**		100 000	**
March 1, 2003, 5⁷/8%		100 000			100 000
March 1, 2028, 6¹/2%		150 000			150 000

Total		1 116 770			1 318 500

Less redeemable bonds classified as current (See Note 3)		(141 600	)		(141 600	)
Less current maturities		(101 940	)		(201 600	)

Net	$	873 230		$	975 300

*: Resource recovery financing
**: Pollution control financing

See Notes to Financial Statements

CONSOLIDATED STATEMENTS OF CAPITALIZATION

	December 31
	1999			1998
	(Thousands of dollars)
LONG-TERM DEBT—CONTINUED
First Mortgage Bonds—NSP-Wisconsin
Series due:
Oct. 1, 2003, 5³/4%	$	40 000		$	40 000
March 1, 2023, 7¹/4%		110 000			110 000
Dec. 1, 2026, 7³/8%		65 000			65 000

Total	$	215 000		$	215 000

Guaranty Agreements—NSP-Minnesota
Series due:
Feb. 1, 1999-2003, 5.41%	$	4 900	**	$	5 100	**
May 1, 1999-2003, 5.70%		22 250	**		22 750	**
Feb. 1, 2003, 7.40%		3 500	**		3 500	**

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, 6⁷/8%	$	250 000
City of Becker Pollution Control Revenue Bonds—Series due Dec. 1, 2005, 7.25%		9 000	**	$	9 000	**
Anoka County Resource Recovery Bond—Series due Dec. 1, 1999-2008, 6.70%—7.15%					20 600	**
Anoka County Resource Recovery Bond—Series due Dec. 1, 2000-2008, 3.95%—4.60%		19 615	*
City of La Crosse Resource Recovery Bond—Series due Nov. 1, 2021, 6%		18 600	*		18 600	*
Viking Gas Transmission Company Senior Notes—Series due:
Oct. 31, 2008, 6.65%		18 845			20 978
Nov. 30, 2011, 7.1%		4 290			4 650
Sept. 30, 2012, 7.31%		11 900			12 833
Sept. 30, 2014, 8.04%		19 667
NRG Energy, Inc. Senior Notes—Series due:
Feb. 1, 2006, 7.625%		125 000			125 000
June 15, 2007, 7.5%		250 000			250 000
June 1, 2009, 7.5%		300 000
Nov. 1, 2013, 8%		240 000
NRG debt secured solely by project assets:
NRG Northeast Generating debt reclassified from short-term (see Note 2)		646 564
Crockett Corp. LLP debt due Dec. 31, 2014, 8.13%		255 000
NRG Energy Center, Inc. (Minneapolis Energy Center) Senior Secured Notes—Series due June 15, 2013, 7.31%		68 881			71 783
Pacific Generation Company debt due 2000-2007, 4.7%—9.9%		26 216			28 586
Various NEO Corporation debt due Jan. 31, 2008, 9.35%		17 390			17 792
Pittsburgh Thermal LP Notes due 2002-2004, 10.61%—10.729%		6 800
San Francisco Thermal LP Notes due Nov. 5, 2004, 10.6%		5 905
COBEE debt due April 21, 2000, 0.0%		5 761
United Power & Land Notes due March 31, 2000, 7.62%		5 208			6 041
Black Mountain Gas Industrial Development Bonds due June 1, 2004, May 1, 2005, 6%		3 000			3 000
Various Eloigne Company Affordable Housing Project Notes due 1999-2027, 1.0%—9.9%		47 116			46 024
Employee Stock Ownership Plan Bank Loans due 1999-2005, Variable Rate		11 606			18 504
Miscellaneous		27 665			9 122

Total		2 394 029			662 513
Less current maturities		(50 591	)		(25 300	)

Net	$	2 343 438		$	637 213

Unamortized discount on long-term debt—net		(8 254	)		(7 017	)

TOTAL LONG-TERM DEBT	$	3 453 364		$	1 851 146

TOTAL CAPITALIZATION	$	6 316 234		$	4 637 732

*: Resource recovery financing
**: Pollution control financing

See Notes to Financial Statements

NOTES TO FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts NSP-Minnesota is primarily a public utility serving customers in Minnesota, North Dakota, South Dakota and Arizona. NSP-Wisconsin serves utility customers in Wisconsin and Michigan. Viking operates an interstate natural gas pipeline. All of the utility companies' 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. In this report, we refer to these companies collectively as NSP.

•: NSP-Wisconsin
•: NRG Energy, Inc.
•: Viking Gas Transmission Co.
•: Energy Masters International, Inc.
•: Eloigne Co.
•: Seren Innovations, Inc.
•: Ultra Power Technologies, Inc.

NSP uses the equity method of accounting for its investments in partnerships, joint ventures and certain projects, mainly at NRG and Eloigne. We record our portion of earnings from international investments after subtracting foreign income taxes. 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, NSP-Wisconsin and Viking, which are allowed in utility rates.

Revenues NSP 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 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.

NSP-Wisconsin's rates include a cost-of-energy adjustment clause for purchased gas, but not for purchased electricity or electric fuel. We can request recovery of those electric costs prospectively through the rate review process, which normally occurs every two years in Wisconsin, and an interim fuel cost hearing process.

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, 8.0 percent in 1998 and 5.75 percent in 1997. 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'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 determines the depreciation of its plant by spreading the original cost equally over the plant's useful life. Every five years, NSP 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 3.83 percent in 1999, 3.77 percent in 1998 and 3.78 percent in 1997.

Decommissioning NSP 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 will recover those costs through rates. (See Note 13 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'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 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 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 9. We discuss our income tax policy for international operations in Note 7.

Foreign Currency Translation NSP's foreign operations generally use the local currency as their functional currency in translating international operating results and balances to U.S. currency. Foreign currency denominated assets and liabilities are translated at the exchange rates in effect at the end of a reporting period. Income, expense and cash flows are translated at weighted-average exchange rates for the period. We accumulate the resulting currency translation adjustments and report them as a component of Accumulated Other Comprehensive Income.

When we convert cash distributions made in one currency to another currency, we include those gains and losses in the results of operations as a component of income from nonregulated businesses before interest and taxes. We do the same for foreign currency derivative arrangements that do not qualify for hedge accounting.

Derivative Financial Instruments To preserve the U.S. dollar value of projected foreign currency cash flows, NRG hedges—or protects—those cash flows if appropriate foreign hedging instruments are available. The gains and losses on those agreements offset the effect of exchange rate fluctuations on NRG's known and anticipated cash flows. NRG defers gains on agreements that hedge firm commitments of cash flows, and accounts for them as part of the relevant foreign currency transaction when the transaction occurs. NRG defers losses on these agreements the same way, unless it appears that the deferral would result in recognizing a loss later.

While NRG is not currently hedging investments involving foreign currency, NRG will hedge such investments when it believes that preserving the U.S. dollar value of the investment is appropriate. NRG is not hedging currency translation adjustments related to future operating results. NRG does not speculate in foreign currencies.

From time to time, NRG also uses interest rate hedging instruments to protect it from an increase in the cost of borrowing. Gains and losses on interest rate hedging instruments are reported as part of the asset for Equity Investments in Nonregulated Projects when the hedging instrument relates to a project that has financial statements that are not consolidated into NRG's financial statements. Otherwise, they are reported as a part of debt.

In the past, EMI used natural gas futures and forward contracts to manage the risk of gas price fluctuations. In February 1999, EMI transferred its gas supply and marketing function to NSP's Energy Marketing division. EMI's remaining gas future and forward contracts will expire during 2000 and EMI will have no further derivative activity.

NSP's Energy Marketing division and NRG's Power Marketing subsidiary use future and forward contracts to manage the risk of natural gas and electricity price fluctuations. The cost or benefit of futures or forward contracts is recorded when related sales commitments are fulfilled as a component of operating expenses. NSP and NRG do not speculate in electricity or natural gas futures.

A final derivative instrument used by NSP and NRG is the interest rate swap. The cost or benefit of the interest rate swap agreements is recorded as a component of interest expense. None of these derivative financial instruments are reflected on NSP's balance sheet. For information on derivatives, see Note 11.

Use of Estimates In recording transactions and balances resulting from business operations, NSP 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.

Cash Equivalents NSP 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.

Regulatory Deferrals As regulated entities, NSP-Minnesota, NSP-Wisconsin and Viking account 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.

Stock-Based Employee Compensation NSP has several stock-based compensation plans, which are described in Note 4. NSP accounts for those plans using the intrinsic value method. We do not record compensation expense for stock options because there is no difference between the market price and the purchase price at grant date. We do, however, record compensation expense for restricted stock that NSP awards to certain employees, but holds until the restrictions lapse or the stock is forfeited. We do not use the optional accounting under SFAS No. 123—Accounting for Stock-Based Compensation. If we had used the SFAS No. 123 method of accounting, the reduction in earnings for 1999, 1998 and 1997 would have been less than 1 cent per share per year.

Development Costs As NRG develops projects, it expenses the development costs it incurs until a sales agreement or letter of intent is signed and the project has received NRG board approval. NRG capitalizes additional costs incurred at that point. When a project begins to operate, NRG amortizes the capitalized costs over either the life of the project's related assets or the revenue contract period, whichever is less. If a project is terminated without becoming operational, NRG expenses the capitalized costs in the year of the termination.

Intangible Assets Goodwill results when NSP purchases an entity at a price higher than the underlying fair value of the net assets. We amortize the goodwill and other intangible assets over periods consistent with the economic useful life of the assets. Our intangible assets are currently amortized over a

range of 15 to 40 years. We periodically evaluate the recovery of goodwill based on an analysis of estimated undiscounted future cash flows. At Dec. 31, 1999, NSP's intangible assets included $41 million of goodwill, net of accumulated amortization.

Intangible and other assets also included deferred financing costs, net of amortization, of approximately $37 million at Dec. 31, 1999. We are amortizing these financing costs over the remaining maturity period of the related debt.

Reclassifications We reclassified certain items in the 1997 and 1998 income statements to conform to the 1999 presentation. These reclassifications had no effect on net income or earnings per share.

2. Short-Term Borrowings

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

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

Nonregulated short-term debt	$	1 026		$	126
Less amounts reclassified to long-term		(647	)

Net nonregulated short-term debt		379			126
Weighted average interest rate—Dec. 31		7.4	%		5.9	%

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 did not borrow or issue any letters of credit against this facility in 1998 or 1999.

In addition, banks provided credit lines of $556 million to wholly owned subsidiaries of NSP at Dec. 31, 1999. At that time, a total of $343 million was borrowed against these lines, mainly by NRG.

On Feb. 22, 2000, NRG Northeast Generating issued $750 million of senior secured bonds to refinance short-term project borrowings. The bond offering included three tranches: $320 million with an interest rate of 8.065 percent due in 2004, $109 million with an interest rate of 8.842 percent due in 2010 and $321 million with an interest rate of 9.292 percent due in 2024. NRG used $647 million of the proceeds to repay short-term borrowings outstanding at Dec. 31, 1999. Accordingly, $647 million of short-term debt has been classified as long-term debt, based on this refinancing.

3. Long-Term Debt

Except for minor exclusions, all property of NSP-Minnesota and NSP-Wisconsin is subject to the liens of the first mortgage indentures, which are contracts between the companies and their bond holders. A lien on the related property secures other debt securities, as we indicate in the Consolidated Statements of Capitalization.

The annual sinking-fund requirements of NSP-Minnesota and NSP-Wisconsin'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 $1 billion

NSP-Minnesota and NSP-Wisconsin may apply property additions in lieu of cash on all series, as permitted by their first mortgage indenture.

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 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:

•: $153 million in 2000
•: $190 million in 2001
•: $42 million in 2002
•: $290 million in 2003
•: $373 million in 2004

4. Common Stock and Incentive Stock Plans

NSP's Articles of Incorporation and first mortgage indenture include certain restrictions on paying cash dividends on common stock. Even with these restrictions, NSP could have paid more than $1.4 billion in additional cash dividends on common stock at Dec. 31, 1999.

NSP grants nonqualified stock options and restricted stock under our Executive Long-Term Incentive Award Stock Plan. The awards granted in any year cannot exceed 1 percent of the number of outstanding shares of NSP common stock at the end of the previous year. When options are exercised or when we grant restricted stock, we may either issue new shares or purchase market shares.

The weighted average number of common and potentially dilutive shares outstanding includes the dilutive effect of stock options and other stock awards based on the treasury stock method. Effective in January 1999, stock options granted to NSP officers vest at a rate of one-third each year for three years. Stock options for other employees vest one year from the date of grant. Once they have vested, options can be exercised up to 10 years after the date they were granted.

Employees forfeit stock options if their employment ends (for reasons other than retirement) before the vesting term. If employment ends after the vesting term, employees either forfeit their options or must exercise them within three to 36 months, depending on their circumstances. If an employee retires, all options granted in 1999 will vest immediately and can be exercised over their 10-year life. The exercise

price of an option is the market price of NSP stock on the date of grant. The plan previously granted other types of performance awards, some of which remain outstanding. Most of these performance awards were valued in dollars, but paid in shares based on the market price at the time of payment. The following table includes transactions that have occurred under the various incentive stock programs, with the corresponding weighted average exercise price:

Stock Option and Performance Awards

	1999				1998				1997
	Shares		Average Price		Shares		Average Price		Shares		Average Price
	(Thousands of shares)
Outstanding Jan. 1	2 389		$	23.57	2 206		$	22.57	2 235		$	21.99
Options granted in January or February	993		$	26.31	572		$	26.88	573		$	23.72
Options and awards exercised	(28	)	$	18.89	(346	)	$	22.39	(520	)	$	21.12
Options and awards forfeited	(8	)	$	26.45	(34	)	$	26.48	(60	)	$	23.60
Options and awards expired	(10	)	$	25.64	(9	)	$	23.24	(22	)	$	25.47

OUTSTANDING AT DEC. 31	3 336		$	24.41	2 389		$	23.57	2 206		$	22.57

EXERCISABLE AT DEC. 31	2 349		$	24.06	1 847		$	23.34	1 685		$	22.21

The following table summarizes information about stock options outstanding at Dec. 31, 1999:

	Range of Exercise Prices
	$16.63-20.47		$21.10-22.75		$23.72-26.88
Options Outstanding: (a)
Number outstanding at Dec. 31, 1999		271 624		715 216		2 336 859
Weighted average remaining contractual life (years)		1.2		4.2		7.9
Weighted average exercise price	$	18.72	$	21.96	$	25.82
Options Exercisable: (a)
Number exercisable at Dec. 31, 1999		271 624		715 216		1 349 786
Weighted average exercise price	$	18.72	$	21.96	$	25.47

(a): There were also 12,197 other awards outstanding at Dec. 31, 1999.

In addition to granting stock options, NSP grants certain employees restricted stock based on a dollar value of the award. We use the market price of the stock on the date it was granted to determine the number of restricted shares to grant. NSP holds the stock until restrictions lapse; 50 percent of the stock vests one year from the date of the award and the other 50 percent vests two years from the date of the award. We reinvest dividends on the shares we hold while restrictions are in place. Restrictions also apply to the additional shares acquired through dividend reinvestment.

Over the last three years, NSP has granted the following restricted stock awards:

•: 52,688 shares in 1997
•: 49,651 shares in 1998
•: 51,790 shares in 1999

Compensation expense related to these awards was immaterial.

5. Benefit Plans and Other Postretirement Benefits

NSP offers the following benefit plans to its benefit employees. Approximately 37 percent of benefit employees are represented by five local labor unions under a collective-bargaining agreement, which expires in 2004.

Pension Benefits NSP 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'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.

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

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

Regulators for almost all of NSP's retail and wholesale customers have allowed full rate recovery of increased benefit costs under SFAS No. 106. Minnesota and Wisconsin retail regulators require external funding to the extent it is tax advantaged. Such funding began for Wisconsin in 1993 and 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.

Reconciliation of Funded Status

	Pension Benefits						Other Postretirement Benefits
	1999			1998			1999			1998
	(Thousands of dollars)
BENEFIT OBLIGATION AT JAN. 1	$	1 143 464		$	1 048 251		$	219 762		$	279 230
Service cost		36 421			31 643			196			3 247
Interest cost		86 429			78 839			9 184			15 896
Plan amendments		184 255			102 315			(80 840	)		(51 456	)
Actuarial (gain) loss		(105 634	)		(41 635	)		8 269			(9 732	)
Benefit payments		(97 086	)		(75 949	)		(16 637	)		(17 423	)

BENEFIT OBLIGATION AT DEC. 31	$	1 247 849		$	1 143 464		$	139 934		$	219 762

Fair value of plan assets at Jan. 1	$	2 221 819		$	1 978 538		$	34 514		$	19 783
Actual return on plan assets		293 904			319 230			3 982			2 471
Employer contributions								13 339			29 683
Benefit payments		(97 086	)		(75 949	)		(16 637	)		(17 423	)

FAIR VALUE OF PLAN ASSETS AT DEC. 31	$	2 418 637		$	2 221 819		$	35 198		$	34 514

Funded status at Dec. 31—net asset (obligation)	$	1 170 788		$	1 078 355		$	(104 736	)	$	(185 248	)
Unrecognized transition (asset) obligation		(311	)		(387	)		22 073			104 482
Unrecognized prior service cost		277 350			114 305			(2 926	)		(2 399	)
Unrecognized net (gain) loss		(1 381 889	)		(1 167 340	)		10 580			3 790

AMOUNT RECOGNIZED IN THE BALANCE SHEETS
Prepaid benefit asset	$	65 938		$	24 933
Accrued benefit liability							$	(75 009	)	$	(79 375	)

WEIGHTED AVERAGE ASSUMPTIONS USED IN BENEFIT CALCULATIONS
Discount rate at end of year		7.5	%		6.5	%		7.5	%		6.5	%
Expected return on plan assets for year—before tax		8.5	%		8.5	%		8.0	%		8.0	%
Rate of future compensation increase per year		4.5	%		4.5	%
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:
1% increase in APBO components at Dec. 31, 1999							$	12 188
1% decrease in APBO components at Dec. 31, 1999								(10 565	)
1% increase in service and interest cost components of the net periodic cost								749
1% decrease in service and interest cost components of the net periodic cost								(646	)

Components of Net Periodic Benefit Cost

	Pension Benefits									Other Postretirement Benefits
	1999			1998			1997			1999			1998			1997
	(Thousands of dollars)
Service cost	$	36 421		$	31 643		$	27 680		$	196		$	3 247		$	5 095
Interest cost		86 429			78 839			72 651			9 184			15 896			18 872
Expected return on plan assets		(147 592	)		(129 263	)		(115 359	)		(2 499	)		(1 582	)		(1 242	)
Amortization of transition (asset) obligation		(76	)		(76	)		(76	)		2 384			8 335			10 780
Amortization of prior service cost		21 210			6 673			1 071			(288	)		(175	)
Recognized actuarial (gain) or loss		(37 397	)		(27 727	)		(20 762	)		(5	)		(4	)		3

Net periodic benefit cost (credit) under SFAS 87 or 106		(41 005	)		(39 911	)		(34 795	)		8 972			25 717			33 508
Credits not recognized due to effects of ratemaking		36 469			35 545			30 862

NET PERIODIC BENEFIT COST (CREDIT) RECOGNIZED FOR FINANCIAL REPORTING	$	(4 536	)	$	(4 366	)	$	(3 933	)	$	8 972		$	25 717		$	33 508

401(k) NSP 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 matches specified amounts of employee contributions to the plan. NSP's matching contributions were approximately $6.5 million in 1999, $4.8 million in 1998 and $4.4 million in 1997.

ESOP NSP has a leveraged Employee Stock Ownership Plan (ESOP) that covers substantially all utility employees. NSP makes contributions to this noncontributory, defined contribution plan to the extent we realize a tax savings from dividends paid on certain ESOP shares. 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 earnings because the contributions are essentially offset by the tax savings provided by the dividends paid on ESOP shares. NSP allocates leveraged ESOP shares to participants when it repays ESOP loans with dividends on stock held by the ESOP.

NSP's ESOP held 11.3 million shares of NSP common stock at the end of 1999 and 1998, and 11.2 million shares of NSP common stock at the end of 1997.

NSP excluded the following uncommitted leveraged ESOP shares from earnings per share calculations: 0.5 million in 1999, 0.6 million in 1998 and 0.6 million in 1997.

6. Nonregulated Earnings Contribution

Income from nonregulated subsidiaries consists of the following:

	1999			1998			1997
	(Thousands of dollars, except per share amounts)
Operating revenues	$	512 839		$	182 230		$	223 571
Equity in operating earnings of unconsolidated affiliates		67 859			79 884			18 600
Operating and development expenses, including project write-downs		(500 803	)		(248 420	)		(251 087	)
Interest and other income (loss), including gains from project sales		(456	)		37 477			20 994

Income from nonregulated businesses before interest and taxes		79 439			51 171			12 078
Interest expense		(97 854	)		(54 261	)		(34 627	)
Income tax benefit		52 761			41 791			38 032

NET INCOME FROM NONREGULATED SUBSIDIARIES	$	34 346		$	38 701		$	15 483

Earnings per share from nonregulated subsidiaries	$	0.22		$	0.26		$	0.11
Loss per share from write-down of investment in CellNet stock		(0.05	)

TOTAL NONREGULATED EARNINGS PER SHARE CONTRIBUTION	$	0.17		$	0.26		$	0.11

7. Income Taxes

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

	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		4.7	%		4.7	%		4.3	%
Tax credits recognized		(13.6	)%		(8.9	)%		(7.9	)%
Equity income from unconsolidated affiliates		(4.2	)%		(3.8	)%		(2.5	)%
Regulatory differences—utility plant items		2.3	%		0.7	%		1.1	%
Other—net		(1.4	)%		(0.6	)%		(1.0	)%

EFFECTIVE INCOME TAX RATE		22.8	%		27.1	%		29.0	%


	(Thousands of dollars)
Income taxes are comprised of the following expense (benefit) items:
Included in utility operating expenses:
Current federal tax expense	$	111 280		$	127 734		$	125 202
Current state tax expense		29 113			32 750			28 812
Deferred federal tax expense		(3 878	)		(6 625	)		(88	)
Deferred state tax expense		(115	)		646			(23	)
Deferred investment tax credits		(9 107	)		(9 122	)		(9 048	)

Total		127 293			145 383			144 855

Included in income taxes on nonregulated operations and nonoperating items:
Current federal tax expense		(15 740	)		(15 732	)		(19 470	)
Current state tax expense		(3 949	)		(6 744	)		(5 804	)
Current foreign tax expense		4 040			2 358			236
Current federal tax credits		(30 137	)		(25 122	)		(17 006	)
Deferred federal tax expense		(4 066	)		11 132			(2 237	)
Deferred state tax expense		(4 097	)		1 566			(662	)
Deferred foreign tax expense		(6 868	)		(7 736	)		(2 892	)
Deferred investment tax credits		(194	)		(310	)		(310	)

Total		(61 011	)		(40 588	)		(48 145	)

TOTAL INCOME TAX EXPENSE	$	66 282		$	104 795		$	96 710

NRG intends to indefinitely reinvest earnings from foreign operations except to the extent the earnings are subject to current U.S. income taxes. Accordingly, U.S. income taxes and foreign withholding taxes have not been provided on a cumulative amount of unremitted earnings of foreign subsidiaries of approximately $195 million and $158 million at Dec. 31, 1999 and 1998. The additional U.S. income tax and foreign withholding tax on the unremitted foreign earnings, if repatriated, would be offset in whole or in part by foreign tax credits. Thus, it is not practicable to estimate the amount of tax that might be payable.

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

	1999		1998
	(Thousands of dollars)
Deferred tax liabilities:
Differences between book and tax bases of property	$	908 320	$	886 099
Regulatory assets		70 546		103 640
Tax benefit transfer leases		23 431		27 170
Other		20 370		22 961

Total deferred tax liabilities	$	1 022 667	$	1 039 870

Deferred tax assets:
Regulatory liabilities	$	49 412	$	75 774
Deferred compensation, vacation and other accrued liabilities not currently deductible		63 073		67 539
Deferred investment tax credits		46 969		51 003
Other		47 000		29 565

Total deferred tax assets	$	206 454	$	223 881

Net deferred tax liability	$	816 213	$	815 989

8. Preferred Securities

At Dec. 31, 1999, various preferred stock series were callable at prices per share ranging from $102.00 to $103.75, plus accrued dividends.

In 1997, a wholly owned special purpose subsidiary trust of NSP 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's consolidation. The preferred securities are redeemable at $25 per share beginning in 2002. Distributions and redemption payments are guaranteed by NSP. Distributions paid to preferred security holders are reflected as a financing cost in the Income Statement along with interest expense.

9. Regulatory Assets and Liabilities

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

	Remaining Amortization Period	1999		1998
	(Thousands of dollars)
AFC recorded in plant (a)	Plant Lives	$	112 291	$	121 551
Conservation programs (a)	3 Years		5 254		72 995
Losses on reacquired debt	Term of Related Debt		52 698		56 242
Environmental costs	Primarily 10 Years		48 708		50 158
Unrecovered gas costs	1-2 Years		15 266		16 259
State commission accounting adjustments (a)	Plant Lives		7 641		7 370
Other	Various		6 269		7 365

TOTAL REGULATORY ASSETS		$	248 127	$	331 940

Deferred income tax adjustments		$	77 433	$	75 066
Investment tax credit deferrals			78 281		84 865
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			18 795		20 683

TOTAL REGULATORY LIABILITIES		$	461 569	$	372 239

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

NOTES TO FINANCIAL STATEMENTS (Continued)

10. Investments Accounted for by the Equity Method

NSP's nonregulated subsidiaries have investments in various international and domestic energy projects, and domestic affordable housing and real estate projects. We use the equity method of accounting for such investments in affiliates, which include joint ventures and partnerships. That's because the ownership structure prevents NSP from exercising a controlling influence over the projects' operating and financial policies. Under this method, NSP records its portion of the earnings or losses of unconsolidated affiliates as equity earnings. A summary of NSP's significant equity method investments follows.

Name	Geographic Area	Economic Interest
Loy Yang Power A	Australia	25.37	%
Enfield Energy Centre	Europe	25.00	%
Gladstone Power Station	Australia	37.50	%
COBEE (Bolivian Power Co.Ltd.)	South America	49.10	%
MIBRAG mbH	Europe	33.33	%
Cogeneration Corp. of America	USA	20.00	%
Schkopau Power Station	Europe	20.95	%
Long Beach Generating	USA	50.00	%
El Segundo Generating	USA	50.00	%
Encina	USA	50.00	%
San Diego Combustion Turbines	USA	50.00	%
Energy Developments Limited	Australia	29.14	%
Scudder Latin American Power	Latin America	6.63	%
Various independent power production facilities	USA	45%—50	%
Various affordable housing limited partnerships	USA	20%—99.9	%

Summarized Financial Information of Unconsolidated Affiliates Summarized financial information for these projects, including interests owned by NSP and other parties, is as follows for the years ended Dec. 31:

Results of Operations

	1999		1998		1997
	(Millions of dollars)
Operating revenues	$	1 752	$	1 509	$	1 698
Operating income	$	215	$	205	$	93
Net income	$	200	$	143	$	84
NSP's equity in earnings of unconsolidated affiliates	$	68	$	80	$	19

Financial Position

	1999		1998
	(Millions of dollars)
Current assets	$	748	$	714
Other assets		7 461		8 071

TOTAL ASSETS	$	8 209	$	8 785

Current liabilities	$	716	$	537
Other liabilities		5 246		5 931
Equity		2 247		2 317

TOTAL LIABILITIES AND EQUITY	$	8 209	$	8 785

NSP's equity investment in unconsolidated affiliates	$	1 047	$	863

11. Financial Instruments

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

	1999				1998
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Thousands of dollars)
Cash, cash equivalents and short-term investments	$	55 968	$	55 968	$	42 364	$	42 364
Long-term investments	$	517 129	$	517 129	$	438 981	$	438 981
Long-term debt, including current portion	$	3 748 195	$	3 626 638	$	2 220 346	$	2 313 468

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'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'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 As of Dec. 31, 1999, NRG had no contracts to hedge—or protect—foreign currency denominated future cash flows. One contract that was outstanding during 1999 had no material effect on earnings.

During the third quarter of 1999, NRG Northeast Generating LLC (N.E. Generating), a wholly owned subsidiary of NRG, entered into $600 million of "treasury locks," at various interest rates, which expired in February 2000. These treasury locks were an interest rate hedge for an N.E. Generating bond offering issued in February 2000 (see Note 2).

At Dec. 31, 1999, NRG had three interest rate swap agreements with notional amounts totaling approximately $393 million. The contracts are used to manage NRG's exposure to changes in interest rates. If the swaps had been discontinued on Dec. 31, 1999, NRG would have owed the counterparties

approximately $3 million. Management believes that NRG's exposure to credit risk due to nonperformance by the counterparties to its hedging contracts is insignificant, based on the investment grade rating of the counterparties.

•: In September 1999, NRG entered into a $200 million swap agreement effectively converting the 7.5 percent fixed rate on its senior notes to a variable rate. It expires on June 1, 2009.
•: A second swap effectively converts a $16 million issue of variable rate debt into fixed rate debt. The swap expires on Sept. 30, 2002.
•: A third swap converts $177 million of floating rate debt into fixed rate debt. The swap expires on Dec. 17, 2014.

As of Dec. 31, 1999, EMI had natural gas forward and futures contracts in the notional amount of less than $1 million. These contracts will expire during 2000 and EMI will have no further derivative activity.

NSP'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.

NRG's Power Marketing subsidiary uses energy forward contracts, along with physical supply, to hedge market risk in the energy market. At Dec. 31, 1999, the notional amount of energy forward contracts was approximately $207 million. If the contracts had been terminated at Dec. 31, 1999, NRG would have received approximately $12 million based on price fluctuations to date. Management believes the risk of counterparty nonperformance with regards to any of NRG's hedging transactions is not significant.

Letters of Credit NSP and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. In addition, NRG uses letters of credit for nonregulated equity commitments, collateral for credit agreements, fuel purchase and operating commitments, and bids on development projects.

At Dec. 31, 1999, there were $140 million in letters of credit outstanding, including $116 million related to NRG commitments. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

12. Joint Plant Ownership

NSP is part owner of an 860-megawatt coal-fired electric generating unit called Sherco 3. NSP owns and has financed 59 percent and Southern Minnesota Municipal Power Agency owns and has financed 41 percent of Sherco 3. NSP is the operating agent under the joint ownership agreement. NSP's share of related expenses for Sherco 3 is included in Utility Operating Expenses. NSP'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.

13. Nuclear Obligations

Fuel Disposal NSP 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's nuclear plants as well as from other U.S. nuclear plants. NSP 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 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 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 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 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 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 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 recorded the DOE's initial assessment of $46 million, which is payable in annual installments from 1993-2008. NSP is amortizing each installment to expense on a monthly basis. The most recent installment paid in 1999 was $4 million; future installments are subject to inflation adjustments under DOE rules. NSP 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's nuclear facilities is planned for the years 2010-2022, using the prompt dismantlement method. NSP 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'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'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 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 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's nuclear decommissioning study and related nuclear plant depreciation capital recovery request in April 1997, using 1993 cost data. Although NSP 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 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 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 plans to reinvest matured securities until decommissioning begins.

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

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

Estimated decommissioning cost obligation in current dollars		977 768
Effect of escalating costs to payment date (at 4.5% 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:

	1999			1998			1997
	(Thousands of dollars)
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 Utility Income and Deductions on the income statement.

A triennial nuclear plant decommissioning filing was made with the MPUC in October 1999. Approval by the MPUC is expected in the first quarter of 2000 and will be effective for cost accruals Jan. 1, 2000.

14. Commitments and Contingent Liabilities

Capital Commitments NSP estimates utility capital expenditures, including purchases of nuclear fuel, will be $490 million in 2000 and $2.3 billion for 2000-2004. There also are contractual commitments for the disposal of spent nuclear fuel. (See Note 13.)

NRG expects to invest approximately $2.7 billion in 2000 and approximately $4.7 billion for 2000-2004 for nonregulated projects and property, which include acquisitions and project investments. NRG's capital requirements may vary significantly. NRG's capital requirements for 2000 reflect expected acquisitions of existing generation facilities, including Cajun, Killingholme A and the Conectiv fossil assets. A significant portion of NRG's capital requirements is expected to be financed by project-secured debt. In addition, NRG may issue a limited amount of equity financing to third parties for funding a portion of the capital requirements.

Seren expects to spend approximately $180 million during 2000, which reflects the build-out of its broadband communications network in Northern California. Seren is evaluating its financing options, including equity financing to third parties and project-secured debt. Seren's capital requirements for 2001-2004 may vary significantly depending on the success of development efforts under way.

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

During 1997 and 1998, NSP executed three separate power purchase agreements (PPA) for a total of 125 megawatts of biomass-fueled generation resources. These contracts would meet the statutory requirements to contract for 125 megawatts of biomass energy by Dec. 31, 1998. However, in December 1999, NSP terminated one of the contracts due to the nonperformance of the vendor. NSP is currently working to replace this contract. At a hearing in December 1999, the MPUC approved two 25-megawatt PPAs and required further reporting by NSP in relation to its efforts to meet the mandate, including whether NSP intends to exercise an option to increase the megawatt size of one of the contracts. Although the agreements met the requirements for biomass scheduled to be operational by Dec. 31, 2001, and Dec. 31, 2002, due to various delays the actual operational dates of the biomass facilities may be later than scheduled.

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 has implemented programs to meet the legislative commitments. NSP'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 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. Under the sales agreements, NSP 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 believes that losses under the loan guarantees, if any, would have an immaterial impact on the results of operations.

Leases Rentals under operating leases were approximately $43 million, $33 million and $32 million for 1999, 1998 and 1997, respectively. Future commitments under these leases generally decline from current levels.

Fuel Contracts NSP 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 is committed to the minimum purchase of approximately $399 million of coal, $21 million of nuclear fuel and $235 million of natural gas and related transportation, or to make payments in lieu thereof, under these contracts. In addition, NSP is required to pay additional amounts depending on actual quantities shipped under these agreements.

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

Power Agreements

	Years	Megawatts
Participation power purchase	2000-2005	500
Seasonal diversity exchanges:
Summer exchanges from MH	2000-2014 2000-2016	150 200
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'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 has an agreement with Minnkota Power Cooperative for the purchase of summer season capacity and energy. NSP will buy 150 megawatts of summer season capacity for approximately $12 million annually in 2000 and 2001. From 2002-2015, NSP will purchase 100 megawatts of capacity for $10 million annually. NSP 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 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.

Wholesale Sales Agreement In 1999, NRG entered into a Standard Offer Service Wholesale Sales Agreement with Connecticut Light & Power Co. (CL&P). NRG will supply CL&P with 35 percent of its standard offer service load during 2000, 40 percent during 2001 and 2002 and 45 percent during 2003. The four-year contract is valued at $1.7 billion. NRG will serve the load with a combination of existing generation and power purchases. Also in 1999, NRG acquired generating stations with a combined capacity of 2,235 megawatts from CL&P.

Nuclear Insurance NSP'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 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 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 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'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 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 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 $35 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, as discussed in Note 13. Other estimates have been recorded for expected environmental costs associated with manufactured gas plant sites formerly used by NSP, 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's nuclear generating plants. See Note 13 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-Wisconsin may be involved in the cleanup and remediation at three sites, including one that NSP-Minnesota is also investigating. One site is a former transformer disposal facility in New Lisbon, Wis., and the remaining two are locations where fuel tanks were installed. The ultimate cleanup and remediation costs of these sites and the extent of NSP-Wisconsin's responsibility, if any, for sharing such costs are not known at this time, but are expected to be immaterial.

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 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's electric operations for two sites formerly used by NSP generating facilities. Accordingly, NSP-Minnesota has recorded an environmental regulatory asset for these costs. NSP-Minnesota may request recovery of costs to remediate other activated sites following the completion of preliminary investigations.

NSP-Wisconsin will be involved in the cleanup and remediation at locations of former manufactured gas plants at Ashland, La Crosse, Eau Claire and Chippewa Falls, Wis. The ultimate cleanup and remediation costs of sites other than Ashland (discussed below) and the extent of NSP-Wisconsin's responsibility, if any, for sharing such costs are not known at this time, but are expected to be immaterial.

The Wisconsin Department of Natural Resources (WDNR) named NSP-Wisconsin as one of three PRPs for creosote and coal tar contamination at the Ashland site. The Ashland site includes property owned by NSP-Wisconsin and two other properties, which include an adjacent city lakeshore park area and a small area of Lake Superior's Chequemegon Bay adjoining the park.

The EPA has accepted a petition from a local environmental group to conduct a preliminary assessment of the Ashland site under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). A preliminary assessment (PA) is a limited scope investigation to evaluate the

potential for hazardous substance releases from a site and also to determine if the site is likely to score at a high enough level to be considered for inclusion on the National Priorities List (NPL). The PA was performed in the second half of 1999 and the results indicated a score sufficiently high to proceed to the next formal step of the EPA scoring under the Hazardous Ranking System (HRS) under CERCLA. The HRS scoring process being performed by the EPA is now under way. NSP-Wisconsin anticipates the WDNR will still act as lead agency on the site. The PA and HRS scoring process will result in a delay in selection of a remedial strategy for the site until later in 2000. NSP-Wisconsin has proposed and WDNR has conceptually approved an interim action (groundwater treatment system) for one operable unit at the site for which NSP-Wisconsin has accepted responsibility. This interim action is expected to be operational by the spring of 2000 and is designed to be a first step in remediating one portion of the site.

The WDNR and NSP-Wisconsin have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary significantly, between $4 million and $93 million, based on different assumptions for methods of remediation and expected results. However, NSP-Wisconsin believes that the estimated costs of the most reasonable and effective solutions are between $24 million and $51 million. During 2000, the WDNR is expected to select the method of remediation for use at the site, after which a more accurate estimate of the cost can be developed. NSP-Wisconsin has already recorded a liability for remediation costs for its portion of the Ashland site, estimated using reasonably effective remedial methods. NSP-Wisconsin has deferred as a regulatory asset the remediation costs accrued for the Ashland site because management expects that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs for other utilities.

In 1998, the EPA published nitrogen oxide (NO^x) emission regulations affecting 22 states, including Wisconsin. The goal of the new regulations is to reduce NO^x emissions by 85 percent by May 1, 2003. Two of NSP-Wisconsin's boilers and eight of its combustion turbines may be affected by this action. If the existing boilers and combustion turbines are made compliant using retrofit technology to control NO^x emissions, it could cost NSP-Wisconsin up to $62 million for capital improvements and add $14 million each year for operation and maintenance expenses. This is the estimated cost of the most expensive alternative to achieve compliance, which is not necessarily the compliance alternative of choice. If the rules are finalized in their most stringent form, other alternatives for these older units may be deemed more cost effective than retrofitting. How the WDNR will implement the new EPA NO^x regulations and their applicability to NSP-Wisconsin are still uncertain.

NSP-Wisconsin has joined with two other Wisconsin-based utilities as well as the Wisconsin Paper Council and Wisconsin Manufacturers and Commerce industrial organizations to request a judicial review of the EPA's final NO^xrules. NSP-Wisconsin believes that the EPA improperly included Wisconsin in the scope of the regulatory action and it improperly calculated potential emissions of NO^x, reducing the allowable emission limits for the state.

In 1999, the EPA was ordered by a federal appeals panel to suspend implementation of the NO^x rules pending further action on a lawsuit brought by another trade group. It is possible that the state of Wisconsin will either not be required to meet the more stringent NO^x requirements or that their implementation will be delayed substantially.

The Clean Air Act calls for phased-in reductions in emissions of sulfur dioxide and nitrogen oxides from electric generating plants. NSP 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 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.

In addition to NSP's utility plants, NRG has several plants throughout the United States, some of which were acquired during 1999. These plants are subject to federal and state emission standards and other environmental regulations. Although NRG continues to study and investigate the methods and costs of complying with these standards and regulations, the future financial effect is not known at this time and may be material.

Several of NSP's facilities contain asbestos, which can be a health hazard to people who come in contact with it. Under governmental requirements, asbestos not readily accessible to the environment need not be removed until the facilities containing the material are demolished. Although the ultimate cost and timing of asbestos removal is not yet known, it is estimated that removal under current regulations would cost $45 million in 1999 dollars. Asbestos removal costs would be recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Environmental liabilities are subject to considerable uncertainties that affect NSP'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 has recorded and/or disclosed its best estimate of expected future environmental costs and obligations.

Legal Claims In the normal course of business, NSP is a party to routine claims and litigation arising from prior and current operations. NSP 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 employees, injured approximately 14 people and damaged several buildings. The accident occurred as a crew from Cable Constructors Inc. (CCI) was installing fiber optic cable for Seren. Seren, CCI and Sirti, an architecture/engineering firm retained by Seren, are named as defendants in 10 lawsuits relating to the explosion. NSP is a defendant in eight of the lawsuits. NSP and Seren deny any liability for this accident. NSP 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 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 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 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 have been filed against NSP by insurance companies that insured

businesses damaged by the fire. It is NSP's position that it is not legally responsible for this unforeseeable event. NSP has a self-insured retention deductible of $2 million, with general liability insurance coverage limits of $150 million. The ultimate cost to NSP, if any, is unknown at this time.

On or about July 12, 1999, Fortistar Capital, Inc. commenced an action against NRG in Hennepin County (Minnesota) District Court, seeking damages in excess of $100 million and an order restraining NRG from consummating the acquisition of Niagara Mohawk Power Corp.'s Oswego generating station. Fortistar's motion for a temporary restraining order was denied and a temporary injunction hearing was held on Sept. 27, 1999. The acquisition of the Oswego generating station was closed on Oct. 22, 1999, following notification to the court of the closing date. NRG intends to continue to vigorously defend the suit and believes Fortistar's claims to be without merit. NRG has asserted numerous counterclaims against Fortistar.

15. Proposed Business Combination

As previously reported in NSP's Report on Form 8-K, dated March 24, 1999, which was filed on March 25, 1999, NSP and NCE agreed to merge and form Xcel Energy. At the time of the merger, each share of NCE common stock will be exchanged for 1.55 shares of Xcel Energy common stock. NSP shares need not be exchanged and will become Xcel Energy shares on a one-for-one basis. Cash will be paid in lieu of any fractional shares of Xcel Energy common stock.

The merger requires approval or regulatory review by certain state utilities regulators, the SEC, the FERC, the Nuclear Regulatory Commission and the Federal Communications Commission, and expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act. During June 1999, shareholders of both NSP and NCE approved the merger. The FERC approved the merger in January 2000. The states of Kansas and Colorado have approved the merger. Merger approval is not required in Michigan, Oklahoma, South Dakota or Wisconsin. NSP and NCE have filed merger applications with regulators in Arizona, Minnesota, New Mexico, North Dakota, Wyoming and Texas, and at the SEC. While NSP cannot guarantee the timing or receipt of the necessary regulatory approvals, NSP currently expects the merger to be completed by the middle of 2000.

The merger is expected to be a tax-free, stock-for-stock exchange for shareholders of both companies (except for fractional shares), and to be accounted for as a pooling of interests. NSP and NCE have agreed to certain undertakings and limitations regarding the conduct of their businesses prior to the closing of the transaction. At the time of the merger, Xcel Energy will register as a holding company under the Public Utility Holding Company Act of 1935.

At Dec. 31, 1999, NSP had deferred approximately $25 million of merger costs, pending the consummation of the business combination and consistent with NSP's filed request for regulatory amortization over future periods.

Xcel Energy Summarized Pro Forma Information The following summary of unaudited pro forma financial information for Xcel Energy gives effect to the merger using the pooling of interests method of accounting. Under this accounting method, NSP's and NCE's balance sheets and income statements are treated as if they have always been combined for financial reporting purposes. This unaudited pro forma summarized financial information should be read in conjunction with the historical financial statements and related notes of NSP and NCE, which are included in the 1999 Annual Reports on Form 10-K of the respective companies.

NOTES TO FINANCIAL STATEMENTS (Continued)

15. Proposed Business Combination (Continued)

The unaudited pro forma balance sheet information at Dec. 31, 1999, assumes the merger had been completed on Dec. 31, 1999. The unaudited pro forma income statement information assumes the merger had been completed on Jan.1, 1999, the beginning of the earliest period presented.

These summarized pro forma amounts do not include any of the estimated cost savings expected to result from the merger of NCE and NSP. Such cost savings, net of the costs incurred to achieve such savings and to complete the merger transaction, are subject to regulatory review and approval. However, the pro forma amounts for NSP and NCE include approximately $25 million and $20 million, respectively, of deferred nonrecurring merger costs as of Dec. 31, 1999, mainly those directly attributable to the merger transaction. Assuming the business combination is accounted for as a pooling of interests, these costs will be expensed upon the consummation of the NCE/NSP merger. The pro forma income statement information amounts do not reflect any of these costs. The pro forma balance sheet information has been adjusted to reflect a write-off of the deferred costs and a related reduction of retained earnings.

In addition to the pro forma balance sheet adjustment discussed above, adjustments have also been made to the historical amounts for NCE and NSP to conform their presentation for pro forma combined reporting, mainly to group nonregulated property with utility plant, and to report nonregulated revenue and operating income with utility amounts.

The unaudited summarized pro forma financial information does not necessarily indicate what the combined company's financial position or operating results would have been if the merger had been completed on the assumed completion dates and does not necessarily indicate future operating results of the combined company.

As of Dec. 31, 1999:

XCEL ENERGY

	NSP		NCE		Adjustments			Pro Forma
	(Millions of dollars)
Plant—Net	$	4 451	$	6 261	$	2 087		$	12 799
Current Assets		1 034		1 027					2 061
Other Assets		4 283		1 034		(2 132	)		3 185

TOTAL ASSETS	$	9 768	$	8 322	$	(45	)	$	18 045

Common Equity	$	2 558	$	2 733	$	(45	)	$	5 246
Preferred Securities		305		294					599
Long-Term Debt		3 454		2 374					5 828

Total Capitalization		6 317		5 401		(45	)		11 673
Current Liabilities		1 826		1 657					3 483
Other Liabilities		1 625		1 264					2 889

TOTAL EQUITY AND LIABILITIES	$	9 768	$	8 322	$	(45	)	$	18 045

For the year ended Dec. 31, 1999:

XCEL ENERGY

	NSP		NCE		Adjustments		Pro Forma
	(Millions of dollars, except for earnings per share)
Revenue	$	2 869	$	3 375	$	625	$	6 869
Operating Income		343		642		237		1 222
Net Income		224		347				571
Available for Common	$	219	$	347			$	566

EARNINGS PER SHARE—DILUTED	$	1.43	$	3.01			$	1.70

New NSP Utility Sub Summarized Pro Forma Information The following summary of unaudited pro forma financial information for New NSP Utility Sub adjusts the historical financial statements of NSP after the transfer of ownership. Upon completion of the merger, all NSP-Minnesota utility assets (other than investments in and assets of subsidiaries) and liabilities associated with the assets will be transferred to New NSP Utility Sub.

The unaudited summarized pro forma financial information does not necessarily indicate what New NSP Utility Sub's financial position or operating results would have been if the merger had been completed on the assumed completion dates and does not necessarily indicate future operating results of New NSP Utility Sub.

As of Dec. 31, 1999:

NEW NSP UTILITY SUB

	NSP		Adjustments			Pro Forma
	(Millions of dollars)
Utility Plant—Net	$	4 451	$	(856	)	$	3 595
Current Assets		1 034		(434	)		600
Other Assets		4 283		(3 416	)		867

TOTAL ASSETS	$	9 768	$	(4 706	)	$	5 062

Common Equity	$	2 558	$	(1 374	)	$	1 184
Preferred Securities		305		(305	)
Long-Term Debt		3 454		(2 077	)		1 377

Total Capitalization		6 317		(3 756	)		2 561
Current Liabilities		1 826		(686	)		1 140
Other Liabilities		1 625		(264	)		1 361

TOTAL EQUITY AND LIABILITIES	$	9 768	$	(4 706	)	$	5 062

For the year ended Dec. 31, 1999:

NEW NSP UTILITY SUB

	NSP		Adjustments			Pro Forma
	(Millions of dollars)
Revenue	$	2 869	$	(236	)	$	2 633
Operating Income		343		(64	)		279
Net Income		224		(74	)		150
AVAILABLE FOR COMMON	$	219	$	(69	)	$	150

16. Segment and Related Information

NSP has four reportable segments: Electric Utility, Gas Utility and two of its nonregulated energy businesses, its wholly owned subsidiaries NRG and EMI.

•: NSP's Electric Utility generates, transmits and distributes electricity primarily in Minnesota, Wisconsin, Michigan, North Dakota and South Dakota. It also makes sales for resale and provides wholesale transmission service to various entities in the United States.
•: NSP's Gas Utility transmits, transports, stores and distributes natural gas and propane primarily in Minnesota, Wisconsin, North Dakota, Michigan and Arizona.
•: NRG develops, builds, acquires, owns and operates several nonregulated energy-related businesses, including independent power production, commercial and industrial heating and cooling, and energy-related refuse-derived fuel production, both domestically and outside the United States.
•: EMI is an energy service company, primarily retrofitting and upgrading facilities for greater energy efficiency, in the United States.

In general, NSP has segmented its operations as either regulated or nonregulated businesses. Further, the regulated businesses are separated between electric and gas; and nonregulated businesses are separated by company (primarily based on product and services). The electric and gas businesses are part of NSP-Minnesota, NSP-Wisconsin and Viking companies and are reviewed at various jurisdiction and/or company levels. They have been aggregated as reportable segments as they are aggregated for reporting to NSP's board of directors. Assets by segment are not reported to management and are not included in the disclosures that follow.

The measure of profit or loss for electric and gas segments reported in the various management reports varies, but the largest component, NSP-Minnesota, reports net income and earnings per share 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. In addition, since NRG and EMI are separate companies, their net income and earnings per share are the measure of profit or loss for both internal management reporting and consolidated external NSP reporting.

To report net income for electric and gas utility segments, NSP-Minnesota and NSP-Wisconsin 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 nonregulated companies, including Eloigne, an affordable housing investment company; Seren, a broadband telecommunications company; Ultra Power, a power-cable testing company; and several other small companies and businesses.

BUSINESS SEGMENTS

	Electric Utility		Gas Utility		NRG			EMI			All Other			Reconciling Eliminations			Consolidated Total (a)
	1999 (Thousands of dollars)
Operating revenues from external customers (b)	$	2 396 263	$	471 780	$	427 567		$	48 017		$	37 255					$	3 380 882
Intersegment revenues		833		4 369		963								$	(5 197	)		968

TOTAL REVENUES	$	2 397 096	$	476 149	$	428 530		$	48 017		$	37 255		$	(5 197	)	$	3 381 850

Depreciation and amortization		322 858		34 857		37 026			2 223			6 098						403 062
Interest income		2 189		658		10 038			52			885			(165	)		13 657
Financing costs, mainly interest expense		121 465		17 055		92 570			318			4 966			(165	)		236 209
Income tax expense (credit)		116 601		8 177		(26 416	)		(8 061	)		(24 019	)					66 282
Equity in earnings (losses) of unconsolidated affiliates						68 947						(1 088	)					67 859
Segment net income (loss)	$	178 908	$	19 458	$	57 195		$	(19 221	)	$	(12 004	)				$	224 336

	Electric Utility		Gas Utility		NRG			EMI			All Other			Reconciling Eliminations			Consolidated Total (a)
	1998 (Thousands of dollars)
Operating revenues from external customers (b)	$	2 361 536	$	456 710	$	98 688		$	54 254		$	29 288					$	3 000 476
Intersegment revenues		815		9 292		1 737								$	(10 916	)		928

TOTAL REVENUES	$	2 362 351	$	466 002	$	100 425		$	54 254		$	29 288		$	(10 916	)	$	3 001 404

Depreciation and amortization		308 415		31 864		16 320			2 129			3 779						362 507
Interest income		9 103		1 403		8 052			184			776			(608	)		18 910
Financing costs, mainly interest expense		109 192		15 485		50 313			108			3 997			(608	)		178 487
Income tax expense (credit)		135 914		10 672		(25 654	)		(4 214	)		(11 923	)					104 795
Equity in earnings (losses) of unconsolidated affiliates						81 706			300			(2 122	)					79 884
Segment net income (loss)	$	226 351	$	17 321	$	41 732		$	(7 659	)	$	4 628					$	282 373

	Electric Utility		Gas Utility		NRG			EMI			All Other			Reconciling Eliminations			Consolidated Total (a)
	1997 (Thousands of dollars)
Operating revenues from external customers (b)	$	2 217 542	$	515 162	$	102 791		$	94 375		$	26 405					$	2 956 275
Intersegment revenues		1 008		6 113		926								$	(7 005	)		1 042

TOTAL REVENUES	$	2 218 550	$	521 275	$	103 717		$	94 375		$	26 405		$	(7 005	)	$	2 957 317

Depreciation and amortization		299 325		28 609		10 310			1 768			3 069						343 081
Interest income		1 696		331		10 806			604			774			(482	)		13 729
Financing costs, mainly interest expense		111 595		13 429		30 729			272			3 626			(482	)		159 169
Merger cost write-off		29 005																29 005
Income tax expense (credit)		122 655		12 087		(23 680	)		(5 921	)		(8 431	)					96 710
Equity in earnings (losses) of unconsolidated affiliates						26 003			(5 144	)		(2 259	)					18 600
Segment net income (loss)	$	199 553	$	22 284	$	21 982		$	(10 841	)	$	4 342					$	237 320

(a): The Consolidated Total amounts for income and expense items represent the sum of utility amounts (including some nonoperating items) from the Statements of Income and the nonregulated amounts from Note 6. 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. However, NRG has significant equity investments for nonregulated projects outside of the United States. Equity in earnings of unconsolidated affiliates, primarily independent power projects, includes $38.6 million in 1999, $29.3 million in 1998 and $27.1 million in 1997 from nonregulated projects located outside of the United States. NRG's equity investments in projects outside of the United States were $606 million in 1999, $557 million in 1998 and $517 million in 1997.

17. Summarized Quarterly Financial Data (Unaudited)

		Quarter Ended
		March 31, 1999		June 30, 1999(a)		Sept. 30, 1999		Dec. 31, 1999(a)
		(Thousands of dollars, except per share amounts)
Utility operating revenues		$	743 183	$	627 157	$	813 482	$	685 189
Utility operating income			87 654		47 944		122 566		85 315
Net income			52 321		11 490		111 337		49 188
Earnings available for common stock			51 261		9 380		110 277		48 126
Earnings per average common share:
Basic		$	0.34	$	0.06	$	0.72	$	0.31
Diluted		$	0.34	$	0.06	$	0.72	$	0.31
Dividends declared per common share		$	0.3575	$	0.3625	$	0.3625	$	0.3625
Stock prices	—high	$	27¹⁵/16	$	26³/4	$	24¹¹/16	$	22¹¹/16
	—low	$	23¹/16	$	22⁹/16	$	20¹⁵/16	$	19⁵/16

		Quarter Ended
		March 31, 1998		June 30, 1998		Sept. 30, 1998(b)		Dec. 31, 1998(c)
		(Thousands of dollars, except per share amounts)
Utility operating revenues		$	701 402	$	638 601	$	766 448	$	712 723
Utility operating income			79 050		65 054		134 985		85 200
Net income			57 117		35 034		101 694		88 528
Earnings available for common stock			54 750		33 974		100 634		87 467
Earnings per average common share:
Basic		$	0.37	$	0.23	$	0.67	$	0.58
Diluted		$	0.37	$	0.23	$	0.67	$	0.58
Dividends declared per common share		$	0.3525	$	0.3575	$	0.3575	$	0.3575
Stock prices	—high	$	29²⁵/32	$	30⁷/32	$	29³/16	$	30¹³/16
	—low	$	26¹/2	$	27¹¹/32	$	25¹¹/16	$	26³/16

(a): 1999 results include two adjustments related to regulatory recovery of conservation program incentives. Second quarter results were reduced by $35 million before taxes, or 14 cents per share, due to the disallowance of 1998 incentives. Fourth quarter results were reduced by $22 million before taxes, or 8 cents per share, due to the reversal of all income recorded through the third quarter for 1999 electric conservation program incentives. In addition, 1999 fourth quarter results include a pretax charge of $17 million, or 8 cents per share, to write off goodwill related to EMI's acquisitions. Also a pretax charge of $11 million, or 4 cents per share, was recorded in the fourth quarter of 1999 to write down an investment in CellNet common stock. In addition, NRG recorded a gain of approximately 3 cents per share on the partial sale of its interest in Cogeneration Corp. of America during the fouth quarter of 1999.
(b): 1998 results include a $22 million pretax charge, which reduced third quarter earnings by 10 cents per share, for the write-down of NRG projects.
(c): 1998 results include a $26 million pretax gain, which increased fourth quarter earnings by 11 cents per share, for a partial sale of an NRG project.

Item 9—Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

During 1999, there were no disagreements with NSP's independent public accountants on accounting procedures or accounting and financial disclosures.

PART III

Item 10—Directors and Executive Officers of the Registrant

CLASS II Nominees for Terms Expiring in 2003

Giannantonio Ferrari, age 60, was named Chief Operating Officer and Executive Vice President of Honeywell International Inc., a worldwide supplier of control technology for home, business and avionics, in December 1999. Prior to that he was the President and Chief Operating Officer of Honeywell Inc. from 1997 through December 1999 when it merged with AlliedSignal Inc. based in Morristown, New Jersey. Ferrari joined Honeywell in 1965 when it started its direct operations in Italy and the Mediterranean area. Through 1980 he held a variety of management positions in that area. He then moved to Brussels, Belgium in 1981 to become Controller & Director of Distribution for Honeywell Europe and Vice-President of Finance & Administration in 1985. In 1988 Giannantonio Ferrari was appointed as Vice President for Western & Southern Europe and promoted to President, Honeywell Europe, Middle East & Africa, out of Brussels, in 1992. Ferrari is on the Board of Directors of Honeywell International Inc. and the Board of Directors, National Association of Manufacturers, and on the Board of Governors, National Electrical Manufacturers Association.

Douglas W. Leatherdale, age 63, is Chairman and Chief Executive Officer of The St. Paul Companies, Inc., a worldwide property and liability insurance organization, having served in such capacity since 1990. Mr. Leatherdale joined The St. Paul Companies in 1972 and has held numerous executive positions with the Company, including President, Executive Vice President and Senior Vice President of Finance. Before joining The St. Paul Companies, Mr. Leatherdale was employed by the Lutheran Church of America in Minneapolis where he served as Associate Executive Secretary on the Board of Pensions. Prior to his four years at the Lutheran Church of America, he served as Investment Analyst Officer at Great West Life Assurance Company in Winnipeg. A native of Canada, Mr. Leatherdale attended United College in Winnipeg and later completed additional studies at Harvard Business School and the University of California-Berkeley. Mr. Leatherdale also serves as a director of The John Nuveen Company and United HealthCare Corporation. He is also vice chairman of the board of directors of the Minnesota Orchestral Association, Chairman of the University of Minnesota Foundation and a trustee of Carleton College. He is a member of the Twin City Society of Security Analysts and the Financial Executives Institute.

A. Patricia Sampson, age 51, currently operates The Sampson Group, Inc., a management development and strategic planning consulting business. Prior to that she served as a consultant with Dr. Sanders and Associates, a management and diversity consulting company. Prior to her current endeavors, Ms. Sampson served as Chief Executive Officer of the Greater Minneapolis Area Chapter of the American Red Cross from July 1993 until January 1, 1995. She also previously served successively as Executive Director from October 1986 until July 1993, Assistant Executive Director-Services (April 1985), and Assistant Manager (July 1984) of the Greater Minneapolis Area Chapter. Prior to the above, she served as the Director of Service to Military Families and Veterans and Director of Disaster Services for the St. Paul Area Chapter of the American Red Cross. Mrs. Sampson received a masters degree from the University of Pennsylvania and a bachelors degree from Youngstown State University. She is a member of the Utility Women's Conference. She is active in Christian education. She serves on the David W. Preus Leadership Award Sponsoring Council. She previously served on the boards of the Greater Minneapolis Area United Way, Minneapolis Urban League, the Minnesota Orchestral Association, and the Minnesota Women's Economic Roundtable.

CLASS I Directors whose Terms Expire in 2002

W. John Driscoll, age 70, was associated with the Rock Island Co. in St. Paul, a private investment company, from 1973 until his retirement as Chairman and Chief Executive Officer in 1994. From 1978 to 1986, Mr. Driscoll was Chairman and a director of First National Bank in Palm Beach, Florida. In 1967, he was co-founder of the Minnesota North Stars National Hockey League team and served as its Chairman until 1978. Earlier, he was General Manager of the Rock Island Corp., a retail lumber, wood millwork and particle board manufacturer and distributor, and worked in sales and sales management for the Weyerhaeuser Co., a wood products firm. He earned a bachelors degree at Yale University. He served in the Marine Corps from 1951 to 1954, which included a tour of duty in Korea. Mr. Driscoll also serves as a director of The John Nuveen Company, The St. Paul Companies, Inc., and Weyerhaeuser Co. Also active in the community, he is a former chairman of the Northwest Area Foundation; former chairman and a life trustee of the Minneapolis Society of Fine Arts; a former chairman and honorary trustee of Macalester College, St. Paul; and a trustee and former president of the Minnesota Landscape Arboretum Foundation.

James J. Howard, age 64, is Chairman, President and Chief Executive Officer of NSP and has served in such capacity since December 1, 1994. He earned a bachelor's degree from the University of Pittsburgh, and in 1969 was awarded a Sloan Fellowship to Massachusetts Institute of Technology where he received his master of science degree in 1970. Before joining NSP as president and CEO in 1987, Mr. Howard was President and Chief Operating Officer of Ameritech, the Chicago-based parent of the Bell companies serving Illinois, Indiana, Michigan, Ohio and Wisconsin. Prior to that, he served as Chairman and CEO of Wisconsin Bell. Mr. Howard is also Chairman of the Federal Reserve Bank of Minneapolis, a director of Ecolab Inc., Honeywell International Inc., ReliaStar Financial Corp. and Walgreen Co. He is also on the Board of Visitors for the University of Pittsburgh, Joseph M. Katz Graduate School of Business in Pittsburgh, Pennsylvania. In addition, Mr. Howard serves as director of the Minnesota Business Partnership, the MEDA Advisory Board, Danny Thompson Memorial Leukemia Foundation, Capital City Partnership, the Minnesota Center for Corporate Responsibility, and is a senior member of The Conference Board, Inc. He also is on the board of advisors for Com-Net Ericsson; a member of the International Energy Agency Coal Industry Advisory Board in Paris, France; a director of the Nuclear Energy Institute, the Edison Electric Institute and the Vice President of the Association of Edison Illuminating Companies, Inc.

Allan L. Schuman, age 65, is Chairman of the Board, President and Chief Executive Officer and a director of Ecolab Inc. in St. Paul, Minnesota. Ecolab develops and manufactures cleaning, sanitizing, and maintenance products for the hospitality, institutional, and industrial markets. Mr. Schuman joined Ecolab in 1957, and became Vice President, Institutional, Marketing and National Accounts in 1972. In 1985 he was named Executive Vice President and in 1988, President, Ecolab Services Group. He was promoted to President and Chief Operating Officer of the Company in August 1992, and named President and Chief Executive Officer in March 1995. Mr. Schuman serves as a director of the Soap and Detergent Association, American Marketing Association Services Council, Hazelden Foundation, the Ordway Music Theatre and the Guthrie Theatre, and chairs the Capital City Partnership. He is also a Trustee of the Culinary Institute of America and of the National Education Foundation of the National Restaurant Association, and a member of the Board of Overseers of Carlson School of Management at the University of Minnesota.

CLASS III Directors whose Terms Expire in 2001

David A. Christensen, age 64, is President, Chief Executive Officer and a director of Raven Industries, Inc. of Sioux Falls, South Dakota, a diversified manufacturer that supplies plastics, electronics and special apparel products to various markets. He has been associated with Raven Industries since 1962. Before joining Raven Industries, he worked at John Morrell & Co. and served in the U.S. Army Corps of Engineers. He received his bachelors degree in industrial engineering from South Dakota State University, which later honored him with its distinguished engineer, distinguished service, and distinguished alumni awards. In 1998, Mr. Christensen was inducted into the South Dakota Hall of Fame. In 1993, he was

honored as South Dakotan of the Year by the University of South Dakota and as South Dakota Sales and Marketing Executive of the Year by Sales and Marketing Executives, Inc. of Sioux Falls, South Dakota. Mr. Christensen also serves as a director of Wells Fargo & Co, San Francisco, California; Beta Raven, Inc., St. Louis, Missouri; and Medcomp Software, Inc., Colorado Springs, Colorado. A strong advocate for his community and state, he has served in many volunteer activities. He is a past director of the South Dakota Symphony and Sioux Falls Downtown Development Corp., as well as a past chairman of the Sioux Empire United Way.

Dr. Margaret R. Preska, age 61, is the President Emerita, Minnesota State University Mankato and Distinguished Service Professor, Minnesota State Colleges and Universities. She was President of Minnesota State University, Mankato, from 1979 until 1992. She had served as its Vice President for Academic Affairs and Equal Opportunity Officer from 1975 until 1979. She previously was academic dean, instructor, assistant and associate professor of history and government at LaVerne College in LaVerne, California. Mr. Preska earned a bachelor of science degree at SUNY Brockport, where she graduated summa cum laude. She earned a masters at The Pennsylvania State University, a Ph.D. at Claremont Graduate University, and further studied at Manchester College of Oxford University. She is an advisory board member of Norwest Bank Minnesota South Central, N.A. in Mankato and a member of Women Directors and Officers in Public Utilities. She served as national president of Camp Fire Boys and Girls, Inc., from 1985-87. She is a charter member of the board of directors of Executive Sports, Inc., a division of Golden Bear International. She is affiliated with several organizations, including: the Retired Presidents Association of the American Association of State Colleges and Universities, the St. Paul/Minneapolis Committee on Foreign Relations, Rotary, Minnesota Women's Economic Roundtable and the American Historical Association.

EXECUTIVE OFFICERS*
Present Positions and Business Experience

Name	Age	During the Past Five Years
James J Howard	64	Chairman of the Board, President and Chief Executive Officer since 12/01/94; and previously Chairman of the Board and Chief Executive Officer.
Paul E Anders Jr	56	Vice President and Chief Information Officer since 5/01/97; and previously Vice President—Information Services at Chrysler Financial Corporation.
Grady P Butts	53	Vice President—Human Resources since 7/01/97; and previously Area Leader—Human Resources Management Services.
Gary R Johnson	53	Vice President and General Counsel since 11/01/91.
Cynthia L Lesher	51	President—NSP Gas since 7/01/97; and previously Vice President—Human Resources.
Edward J McIntyre	49	Vice President and Chief Financial Officer since 1/01/93.
John P Moore, Jr	53	Vice President and Corporate Secretary since 4/01/99; Corporate Secretary since 7/01/97; and previously General Counsel and Corporate Secretary for NSP-Wisconsin.
Paul E Pender	45	Vice President—Finance and Treasurer since 5/01/97; and previously Assistant Treasurer and Director, Corporate Finance.
Roger D Sandeen	54	Vice President and Controller since 7/01/89; and previously Chief Information Officer from 5/01/92 to 4/30/97.
David M Sparby	45	Vice President—Regulatory Services since 9/1/98; and previously Director—Regulatory Services.
Loren L Taylor	53	President—NSP Electric since 10/27/94; and previously Vice President—Customer Operations.
Michael D Wadley	43	President—Nuclear Generation since 6/16/98; Vice President—Nuclear Generation from 2/03/97 to 6/15/98; Nuclear Plant Manager—Prairie Island from 10/26/95 to 2/02/97; and previously Plant Manager —Prairie Island.

*: As of 3/01/2000

Item 11—Executive Compensation

The following table sets forth cash and non-cash compensation for each of the last three fiscal years ended December 31, 1999, for services in all capacities to the Company and its subsidiaries, to the Chief Executive Officer and the next four highest compensated executive officers of the Company.

SUMMARY COMPENSATION TABLE

	Annual Compensation				Long-Term Compensation Awards		Payouts
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)
Name & Principal Position	Year	Salary($)	Bonus($)(1)	Other Annual Compensation ($)(2)	Restricted Stock Awards ($)(3)	Number of Securities Underlying Options and SARs (#)	LTIP Payouts ($)(4)	All Other Compensation ($)(5)
James J. Howard Chairman, President & Chief Executive Officer	1999 1998 1997	730,000 700,000 672,000	233,346 286,300 197,000	29,072 9,578 11,705	335,800 441,000 477,120	147,040 32,558 35,416	0 0 0	22,178 19,545 23,429
Paul E Anders, Jr.(6) Vice President and Chief Information Officer	1999 1998 1997	296,000 285,000 183,334	231,100 263,500 236,000	1,706 5,461 12,651	79,920 105,450 0	28,124 11,134 0	0 0 0	8,024 4,211 5,671
Edward J. McIntyre Vice President & Chief Financial Officer	1999 1998 1997	375,000 340,000 260,000	92,200 96,300 58,000	1,646 2,444 961	101,250 125,800 109,200	42,755 13,284 11,510	0 0 0	9,000 15,283 11,412
Loren L. Taylor President, NSP Electric	1999 1998 1997	298,000 240,000 232,000	68,500 103,600 65,000	1,239 1,401 1,134	80,460 88,800 97,440	28,314 9,376 10,270	0 0 0	9,631 9,434 15,537
Gary R. Johnson Vice President & General Counsel	1999 1998 1997	260,000 240,000 229,000	71,300 95,600 48,000	1,750 984 1,362	70,200 88,800 96,180	24,703 9,376 10,138	0 0 0	10,201 19,191 18,683

(1): This column consists of awards made to each named executive under the Company's current Executive Annual Incentive Program and, with respect to Mr. Anders, also includes an additional payment of $150,000 in each of 1997, 1998 and 1999 to replace compensation opportunities that Mr. Anders forfeited when he left his previous employer.
(2): This column consists of reimbursements for taxes on certain personal benefits received by the named executives.
(3): Amounts shown in this column reflect the market value of the shares of restricted stock awarded under the LTIP, and are based on the closing price of the Company's common stock on the date that the awards were made. Restricted shares earned for 1999 under the Company's LTIP were granted on January 26, 2000 based on the performance period ending September 30, 1999. As of December 31, 1999, the named executives held the following as a result of grants under the LTIP: Mr. Howard held 26,771 restricted shares at a market value of $522,034.50; Mr. Anders held 4,061 restricted shares at a market value of $79,189.50; Mr. McIntyre held 7,085 restricted shares at a market value of $138,157.50; Mr. Taylor held 5,418 restricted shares at a market value of $105,651.00 and Mr. Johnson held 5,392 restricted shares at a market value of $105,144.00. The restricted stock awards vest one year after the date of grant with respect to fifty (50%) of the shares and two years after such date with respect to the remaining shares, conditioned upon the continued employment of the recipient with the Company. Regular dividends are paid on the restricted shares.

The total number of restricted shares awarded for the years 1997, 1998 and 1999 are as follows: 51,388 shares for Mr. Howard, 8,025 shares for Mr. Anders, 13,940 shares for Mr. McIntyre, 11,064 shares for Mr. Taylor and 8,696 shares for Mr. Johnson.

(4): The Company had no LTIP payouts in 1999.

(5): This column consists of the following: $1,114.17 was contributed by the Company for the Employee Stock Ownership Plan (ESOP) for each named executive officer (the Company contribution on behalf of all ESOP participants, including the named executive officers was equal to .69% of their covered compensation); the value to each named executive of the remainder of insurance premiums paid under the Officer Survivor Benefit Plan by the Company: $19,059 for Mr. Howard, $5,710 for Mr. Anders, $3,828 for Mr. McIntyre, $6,486 for Mr. Taylor and $5,232 for Mr. Johnson; imputed income as a result of life insurance paid by the Company on behalf of each named executive: $805 for Mr. Howard, $0 for Mr. Anders, $775.25 for Mr. McIntyre, $830.40 for Mr. Taylor and $739.20 for Mr. Johnson; Company matching 401(k) plan contribution of $1,200 to each named executive; and earnings accrued under the Company Deferred Compensation Plan to the extent such earnings exceeded the market rate of interest (as prescribed pursuant to the SEC rules), which was $0 for Mr. Howard, $0 for Mr. Anders, $2,082.40 for Mr. McIntyre, $0 for Mr. Taylor and $1,915.88 for Mr. Johnson.
(6): Mr. Anders joined the Company in May 1997.

OPTIONS AND STOCK APPRECIATION RIGHTS (SARs)

The following table indicates for each of the named executives (i) the extent to which the Company used stock options and SARs for executive compensation purposes in 1999 and (ii) the potential value of such options and SARs as determined pursuant to the SEC rules.

Options and SARs Granted in 1999

	Individual Grants						Potential Realizable Value at Assumed Annual Rates of Stock Price Appreciation for Option Term
(a)	(b)	(c)		(d)		(e)	(f)		(g)
Name	Options/ SARs Granted(1) (#)	% of Total Options and SARs Granted to Employees in 1999		Exercise or Base Price ($/Sh)		Expiration Date	5%($)(2)		10%($)(2)
J. Howard	147,040 options	14.76	%	$	26.3125	1/27/09	$	2,433,187	$	6,166,174
P. Anders Jr	28,124 options	2.82	%	$	26.3125	1/27/09	$	465,390	$	1,179,390
E. McIntyre	42,755 options	4.29	%	$	26.3125	1/27/09	$	707,501	$	1,792,946
L. Taylor	28,314 options	2.84	%	$	26.3125	1/27/09	$	468,534	$	1,187,357
G. Johnson	24,703 options	2.48	%	$	26.3125	1/27/09	$	408,780	$	1,035,929
All Shareholders(3)	N/A	N/A			N/A	N/A	$	6,559,361,006	$	10,444,686,152

(1): Options were granted on January 27, 1999 and vest in equal annual installments over three years. No SARs were awarded for 1999.
(2): The hypothetical potential appreciation shown in columns (f) and (g) for the named executives is required by the SEC rules. The amounts in these columns do not represent either the historical or anticipated future performance of the Company's common stock level of appreciation.
(3): Potential realizable values during the ten year period commencing January 27, 1999, are based on the market price ($26.3125) and the outstanding shares (153,040,619) of common stock of the Company on that date.

The following table indicates for each of the named executives the number and value of exercisable and unexercisable options and SARs as of December 31, 1999.

Aggregated Option and SAR Exercises in 1999 and FY-End Option/SAR Value

					(e)
			(d)		Value of Unexercised In-the-Money Options and SARs at 12/31/99 ($) Exercisable (ex)/ Unexercisable (unex)*
(a)	(b)	(c)	Number of Unexercised Options and SARs at 12/31/99 (#) Exercisable (ex)/ Unexercisable (unex)
Name	Shares Acquired on Exercise(#)	Realized Value($)
J. Howard	N/A	N/A	240,099 147,040	(ex) (unex)	136,184	(ex) (unex)
P. Anders Jr	N/A	N/A	11,134 28,124	(ex) (unex)		(ex) (unex)
E. McIntyre	N/A	N/A	83,660 42,755	(ex) (unex)	48,279	(ex) (unex)
L. Taylor	N/A	N/A	54,951 28,314	(ex) (unex)	3,347	(ex) (unex)
G. Johnson	N/A	N/A	61,010 24,703	(ex) (unex)	4,463	(ex) (unex)

*: Share price on December 31, 1999 was $19.5000. Unexercisable options were granted on January 27, 1999 at a price of $26.3125. No SARs were granted in 1999.

Pension Plan Table

As of January 1, 1999, pension benefits were changed. Prior to January 1, 1999, each nonbargaining employee was given an opportunity to choose between two retirement programs, the Traditional Program and the Pension Equity Program. All of the executive officers named in the Summary Compensation Table chose the Traditional Program for their pension benefits.

Under the Traditional Program, the annual compensation used to calculate the average compensation uses base salary for the year, and, for certain individuals, including Messrs. Howard, McIntyre, Taylor and Johnson, bonus compensation paid in that same year. After an employee has reached 30 years of service, no additional years of service are used in determining the pension benefit under the Traditional Program. The basic pension benefit under the Traditional Program payable at age 65 is the same as the benefit payable under the pension plan as of December 31, 1998. The benefit amounts under the Traditional Program are computed in the form of a straight-life annuity. Both programs, the Traditional Program and the Pension Equity Program, feature a cash balance side account which credits $1,400 annually, plus interest each year. The opening balance as of January 1, 1999 was $1,400 times years of service.

The following table illustrates the approximate retirement benefits payable under the Traditional Program to employees retiring at the normal retirement age of 65 years:

		Years of Service
		Estimated Annual Benefits for Years of Service Indicated
Average Compensation (4 Years)
Average Compensation (4 Years)		5		10		15		20		25		30
$	50,000	$	4,000	$	8,500	$	13,500	$	19,000	$	24,500	$	31,500
$	100,000	$	8,500	$	17,000	$	25,500	$	35,000	$	45,000	$	56,000
$	150,000	$	12,500	$	25,000	$	38,000	$	51,500	$	65,500	$	80,500
$	200,000	$	16,500	$	33,000	$	50,000	$	67,500	$	86,000	$	105,000
$	250,000	$	20,500	$	41,500	$	62,500	$	84,000	$	106,500	$	129,500
$	300,000	$	24,500	$	49,500	$	74,500	$	100,500	$	126,500	$	154,000
$	350,000	$	28,500	$	57,500	$	87,000	$	116,500	$	147,000	$	178,500
$	400,000	$	33,000	$	66,000	$	99,000	$	133,000	$	167,500	$	203,000
$	450,000	$	37,000	$	74,000	$	111,500	$	149,500	$	188,000	$	227,500
$	500,000	$	41,000	$	82,000	$	123,500	$	165,500	$	208,500	$	252,000
$	550,000	$	45,000	$	90,500	$	136,000	$	182,000	$	229,000	$	276,500
$	600,000	$	49,000	$	98,500	$	148,000	$	198,500	$	249,000	$	301,000
$	650,000	$	53,000	$	106,500	$	160,500	$	214,500	$	269,500	$	325,500
$	700,000	$	57,500	$	115,000	$	172,500	$	231,000	$	290,000	$	350,000
$	750,000	$	61,500	$	123,000	$	185,000	$	247,500	$	310,500	$	374,500
$	800,000	$	65,500	$	131,000	$	197,000	$	263,500	$	331,000	$	399,000
$	850,000	$	69,500	$	139,500	$	209,500	$	280,000	$	351,500	$	423,500
$	900,000	$	73,500	$	147,500	$	221,500	$	296,500	$	371,500	$	448,000
$	950,000	$	77,500	$	155,500	$	234,000	$	312,500	$	392,000	$	472,500
$	1,000,000	$	82,000	$	164,000	$	246,000	$	329,000	$	412,500	$	497,000
$	1,050,000	$	86,000	$	172,000	$	258,500	$	345,500	$	433,000	$	521,500
$	1,100,000	$	90,000	$	180,000	$	270,500	$	361,500	$	453,500	$	546,000
$	1,150,000	$	94,000	$	188,500	$	283,000	$	378,000	$	474,000	$	570,500
$	1,200,000	$	98,000	$	196,500	$	295,000	$	394,500	$	494,000	$	595,000
	wage base:	$	72,600

At the end of 1999, each of the executive officers named in the Summary Compensation Table had the following credited service: Mr. Howard, 12.92 years, Mr. Anders, 2.67 years, Mr. McIntyre, 26.83 years, Mr. Taylor, 26.58 years and Mr. Johnson, 21.08 years.

An employment agreement with Mr. Howard provides that he and his spouse, if she survives him, will receive a lump-sum payment equal to the present value of combined benefits from the Pension Plan and supplemental Company payments as though he had completed 30 years of service, less the pension benefits earned from a former employer. For purposes of the employment agreement, the present value of the lump sum payment will be calculated using a discount rate based on the interest rate for valuing immediate annuities used by the Pension Benefit Guaranty Corporation, which is now different from the GATT rate utilized for other employees.

An employment agreement with Mr. Anders provides that he will receive payments equal to the combined benefits from the Pension Plan and supplemental Company payments as though his service with a former employer were included in determining benefits under the Company's pension plans, less the pension benefits earned from a former employer. Benefits under the employment agreement will include incentive payments in determining the final average compensation.

Employment Agreements and Severance Arrangements

At the time we entered into the merger agreement with New Century Energies, we also entered into a new employment agreement with Mr. Howard, which will replace his current employment agreement when the merger takes place. Under this new agreement, Mr. Howard will continue to be an employee of Xcel Energy and will serve as Chairman of the Board of Directors of Xcel Energy for one year following the merger. He will also be forbidden from competing with Xcel Energy and its affiliates for two years following the termination of his employment or for one year after the merger, whichever is longer, and from disclosing confidential information of Xcel Energy and its affiliates.

Under his new employment agreement, Mr. Howard will receive the following compensation and benefits during the year following the merger:

•: a base salary not less than the higher of his base salary immediately before the merger and his current base salary of $730,000;
•: an annual bonus on the same basis as other senior executives, with a target bonus of 65% of his base salary;
•: the same employee benefits as other senior executives of Xcel Energy; and
•: the same fringe benefits as he receives under his current employment agreement.

In addition, Mr. Howard will receive a special retention bonus in recognition of:

•: his remaining employed for one year following the merger, even though he will no longer be chief executive officer;
•: the special efforts he will be making to cause the merger to take place and to implement a successful transition to combined operations of Northern States Power and New Century Energies; and
•: his agreement to the noncompetition and confidentiality covenants described above.

If the merger does take place and Mr. Howard remains employed for one year after the merger, he will be paid a special retention bonus of $7.6 million one year after the merger. If the merger does not take place, or if the merger takes place but Mr. Howard dies or becomes disabled within one year after the merger, a special retention bonus of $2.5 million will be paid on the day his employment terminates. In either case, $2.5 million is being paid specifically for the noncompetition and confidentiality covenants described above, and Mr. Howard will be obligated to return that amount if he breaches the covenants in any material way.

If Mr. Howard's employment were to be terminated by Xcel Energy without cause or if he were to terminate his employment for good reason after the merger, he would be entitled to receive the compensation and benefits described above as if he had remained employed under the new employment agreement for the remainder of the year following the merger. Mr. Howard's new employment agreement also preserves the supplemental retirement benefit to which he is entitled under his current employment agreement. Finally, Xcel Energy is obligated to make Mr. Howard whole for any excise tax on excess parachute payments that he may incur.

We adopted a 1999 senior executive severance policy shortly before we entered into the merger agreement. This policy will continue for five years, and may be extended beyond five years. All of the executive officers of Northern States Power other than Mr. Howard participate in the policy.

Under the policy, a participant whose employment is terminated at any time before the third anniversary of the merger will receive severance benefits unless

•: the employer terminated the participant for cause;
•: the termination was because of the participant's death, disability, or retirement;
•: the division or subsidiary in which the participant worked was sold and the buyer agreed to continue the participant's employment with specified protections for the participant; or
•: the participant terminated voluntarily without good reason. To receive the severance benefits, the participant must also sign an agreement releasing all claims against the employer and its affiliates, and agreeing not to compete with the employer and its affiliates and not to solicit their employees and customers.

The severance benefits for executive officers under the policy include the following:

•: a cash payment equal to 2.5 times the participant's annual base salary, annual bonus and annualized long-term incentive compensation, plus pro-rated incentive compensation for the year of termination;
•: a cash payment equal to the additional amounts that would have been credited to the executive under pension and retirement savings plans, if the participant had remained employed for another 2.5 years;
•: continued welfare benefits for 2.5 years;
•: financial planning benefits for two years, and outplacement services costing not more than $30,000; and
•: an additional cash payment to make the participant whole for any excise tax on excess parachute payments that he or she may incur, with certain limitations specified in the policies.

The benefits under the severance policy described above will be reduced by any severance benefits that the participant receives under the senior executive severance policy that we adopted in 1995.

We cannot be sure whether any executive officers of Northern States Power will terminate employment and receive severance benefits. Also, even if we assume that they will get the benefits, the actual amount of the benefits will depend on when their employment actually terminates and other factors which we cannot now determine. However, based on current compensation levels, we have estimated that if (1) the merger had occurred on March 24, 2000, (2) all of our executive officers were terminated at the time the merger occurred, and (3) the other assumptions we used to make the calculations are correct, then the cash payments they would receive under the policies would be approximately as follows: Edward J. McIntyre, $4.1 million; Paul E. Anders, $2.6 million; Loren L. Taylor, $3.0 million; and Gary R. Johnson, $2.6 million; all other executive officers of Northern States Power as a group, $27.4 million. These amounts assume that they will be required to pay excise tax on excess parachute payments.

Director Compensation

Employees of the Company receive no separate compensation for service as a director. During 1999, directors not employed by the Company received a $25,000 annual retainer (or a pro rata portion if service was less than 12 months) and $1,200 for each Board and Committee meeting attended. These directors also received a grant of stock equivalent units under the Stock Equivalent Plan for Non-Employee Directors, which was established in 1996 and is described below. Additionally, a $2,800 annual retainer was paid to each elected Committee Chairperson.

In 1996, we established a Stock Equivalent Plan for Non-Employee Directors (the "Stock Equivalent Plan") to more closely align directors' interests with those of our shareholders. Under the Stock Equivalent Plan, directors may receive an annual award of stock equivalent units with each unit having a value equal to one share of common stock of the Company. Stock equivalent units do not entitle a director to vote and are only payable as a distribution of whole shares of the Company's common stock upon a director's termination of service. The stock equivalent units fluctuate in value as the value of common stock of the Company fluctuates. Additional stock equivalent units are accumulated upon the payment of and at the same value as dividends declared on common stock of the Company. On April 29, 1999, non-employee directors each received an award of 872.344 stock equivalent units totaling approximately $20,800 in cash value. Additional stock equivalent units were accumulated during 1999 as dividends were paid on common stock of the Company. The number of stock equivalents for each non-employee director is listed in the share ownership chart which is set forth below.

Directors also may participate in a deferred compensation plan which provides for deferral of director retainers and meeting fees until after retirement from the Board of Directors. A director may defer director retainer and meeting fees into the Stock Equivalent Plan.

Item 12—Security Ownership of Certain Beneficial Owners and Management

Share Ownership of Directors, Nominees and Named Executive Officers

The following table lists the beneficial ownership of NSP common stock owned as of February 29, 2000, by (i) the Company's directors and nominees, (ii) the executive officers named in the Summary

Compensation Table that follows and (iii) all the directors and executive officers of the Company as a group. None of these individuals owns any shares of NSP Preferred Stock.

Name of Beneficial Owner	Common Stock	Stock Equivalents(1)	Acquirable Within 60 Days(2)	Restricted Stock	Total
David A. Christensen	1,000	13,560			14,560
W. John Driscoll	4,000	12,833			16,833
Giannantonio Ferrari		6,036			6,036
James J. Howard	85,960		289,412	26,090	401,642
Douglas W. Leatherdale	600	13,017			13,617
Margaret R. Preska	1,200	11,656			12,856
A. Patricia Sampson	972	11,656			12,628
Allan L. Schuman	200	1,608			1,808
Paul E. Anders Jr	3,435		20,508	6,219	30,162
Edward J. McIntyre	30,573		98,018	7,726	136,317
Loren L. Taylor	25,976		64,408	5,920	96,304
Gary R. Johnson	12,034		69,016	5,387	86,437
Directors and executive officers as a group	219,812	70,366	699,685	72,529	1,062,392

(1): Represents stock units awarded under the Stock Equivalent Plan for Non-employee Directors as of February 29, 2000.
(2): Represents exercisable options and performance units under the current Long-Term Incentive Program (LTIP) as of February 29, 2000. Options to purchase common stock of the Company which are exercisable within the next 60 days are 286,385 option shares for Mr. Howard, 20,508 option shares for Mr. Anders, 96,945 option shares for Mr. McIntyre, 64,218 option shares for Mr. Taylor and 69,016 option shares for Mr. Johnson. The number of shares that would have been payable upon the exercise of performance units on February 29, 2000 are: 3,027 for Mr. Howard, 0 for Mr. Anders, 1,073 for Mr. McIntyre, 190 for Mr. Taylor and 0 for Mr. Johnson.

Item 13—Certain Relationships and Related Transactions

No related transactions.

PART IV

Item 14—Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a)	1.	Financial Statements	Page
		Included in Part II of this report:
		Report of Independent Accountants for the years ended Dec. 31, 1999, 1998 and 1997.	34
		Consolidated Statements of Income for the three years ended Dec. 31, 1999.	35
		Consolidated Statements of Cash Flows for the three years ended Dec. 31, 1999.	36
		Consolidated Balance Sheets, Dec. 31, 1999 and 1998.	37
		Consolidated Statements of Changes in Common Stockholders' Equity for the three years ended Dec. 31, 1999.	38
		Consolidated Statements of Capitalization, Dec. 31, 1999 and 1998.	39
		Notes to Financial Statements.	41

(a)	2.	Financial Statement Schedules
		Schedules are omitted because of the absence of the conditions under which they are required or because the information required is included in the financial statements or the notes.
(a)	3.	Exhibits
			*	Indicates incorporation by reference
		2.01	*	Agreement and Plan of Merger, dated as of March 24, 1999, by and between Northern States Power Company and New Century Energies, Inc. (Incorporated by reference to Exhibit 2.1 to the Report on Form 8-K (File No. 1-12907) of New Century Energies, Inc. dated March 24, 1999.
		3.01	*	Restated Articles of Incorporation of the Company and Amendments. (Exhibit 3.01 to Form 10-Q for the quarter ended June 30, 1998, File No. 1-3034).
		3.02	*	Bylaws of the Company as amended March 26, 1997, and ratified by NSP's shareholders on June 25, 1997. (Exhibit 3.02 to Form 10-K for the year 1997, File No. 1-3034).
		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 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 4.01 AA 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).
4.45	*	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).

100

4.49	*	Trust Indenture, dated April 1, 1947, from NSP-Wisconsin to Firstar Trust Company (formerly First Wisconsin Trust Company), as Trustee. (Exhibit 7.01 to File No. 2-6982).
		Supplemental Indentures between NSP-Wisconsin and said Trustee, supplemental to Exhibit 4.49 dated as follows:
4.50	*	March 1, 1949 (Exhibit 7.02 to File No. 2-7825).
4.51	*	June 1, 1957 (Exhibit 2.13 to File No. 2-13463).
4.52	*	Aug. 1, 1964 (Exhibit 4.20 to File No. 2-23726).
4.53	*	Dec. 1, 1969 (Exhibit 2.03E to File No. 2-36693).
4.54	*	Sept. 1, 1973 (Exhibit 2.03F to File No. 2-49757).
4.55	*	Feb. 1, 1982 (Exhibit 4.01G to File No. 2-76146).
4.56	*	March 1, 1982 (Exhibit 4.08 to Form 10-K for the year 1982, File No. 10-3140).
4.57	*	June 1, 1986 (Exhibit 4.01I to File No. 33-6269).
4.58	*	March 1, 1988 (Exhibit 4.01J to File No. 33-20415).
4.59	*	Supplemental and Restated Trust Indenture dated March 1, 1991, from NSP-Wisconsin to Firstar Trust Company (formerly First Wisconsin Trust Company), as Trustee. (Exhibit 4.01K to File No. 33-39831).
4.60	*	April 1, 1991 (Exhibit 4.01L to File No. 33-39831).
4.61	*	March 1, 1993 (Exhibit 4.01 to Form 8-K dated March 4, 1993, File No. 10-3140).
4.62	*	Oct. 1, 1993 (Exhibit 4.01 to Form 8-K dated September 21, 1993, File No. 10-3140).
4.63	*	Dec. 1, 1996 (Exhibit 4.01 to Form 8-K dated December 12, 1996, File No. 10-3140).
4.64	*	NSP Employee Stock Ownership Plan. (Exhibit 4.60 to Form 10-K for the year 1994 File No. 1-3034).
4.65	*	Subordinated Debt Securities Indenture, dated as of Jan. 30, 1997, between NSP and Norwest Bank Minnesota, National Association, as trustee. (Exhibit 4.02 to Form 8-K dated Jan. 28, 1997, File No. 001-03034) .
4.66	*	Preferred Securities Guarantee Agreement, dated as of Jan. 31, 1997, between NSP and Wilmington Trust Company, as Trustee. (Exhibit 4.05 to Form 8-K dated Jan. 28, 1997, File No. 001-03034) .
4.67	*	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) .
4.68	*	Supplemental Indenture, dated as of Jan. 31, 1997, between NSP 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).
4.69	*	Common Securities Guarantee Agreement dated as of Jan. 31, 1997, between NSP and Wilmington Trust Company, as Trustee. (Exhibit 4.13 to Form 8-K dated Jan. 28, 1997, File No. 001—03034) .
4.70	*	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).

101

4.71	*	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).
4.72	*	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) .
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).
Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
10.08	*	Summary of Terms and Conditions of Employment of James J Howard, Chairman, President and Chief Executive Officer, effective Feb. 1, 1987, as amended and restated effective as of Jan. 28, 1998. (Agreement filed as Exhibit 10.03 to Form 10-Q for the quarter ended March 31, 1998, File No. 1-3034).
10.09	*	NSP Severance Plan. (Exhibit 10.12 to Form 10-K for the year 1994, File No. 1-3034).
10.10	*	NSP Deferred Compensation Plan amended effective Jan. 1, 1993. (Exhibit 10.16 to Form 10-K for the year 1993, File No. 1-3034).
10.11	*	Amended and Restated Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.02 to Form 10-Q for the quarter ended March 31, 1998, File No. 1-3034).
10.12	*	Executive Annual Incentive Award Plan for 1998. (Exhibit 10.01 to Form 10-Q for the quarter ended March 31, 1998, File No. 1-3034).
10.13	*	Stock Equivalent Plan for Non-Employee Directors of Northern States Power Company As Amended and Restated Effective Oct. 1, 1997. (Exhibit 10.15 to Form 10-K for the year 1997. File No. 1-3034.)

102

	10.14	*	Employment Contract of James J. Howard dated March 24, 1999. (Exhibit 10.14 to Form 10-K for the year 1999. File No. 1-3034.)
	12.01		Statement of Computation of Ratio of Earnings to Fixed Charges.
	21.01		Subsidiaries of the Registrant.
	23.01		Consent of Independent Accountants—PricewaterhouseCoopers LLP, Minneapolis, Minn.
	99.01		Statement pursuant to Private Securities Litigation Reform Act of 1995.
	99.02	*	Description of Business of NRG Energy, Inc. (Item 1 of NRG Energy, Inc.'s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 1999, File No. 333-33397).
	99.03		Unaudited Pro Forma Condensed Balance Sheets for Xcel Energy, Inc. at Dec. 31, 1999, and Unaudited Pro Forma Condensed Statements of Income for the three years ended Dec. 31, 1999.
	99.04		Unaudited Pro Forma Condensed Balance Sheets for New NSP Utility Sub. at Dec. 31, 1999, and Unaudited Pro Forma Condensed Statements of Income for the three years ended Dec. 31, 1999.
	99.05		Description of Common Stock.
	27.01		Financial Data Schedule for 1999.
(b)	Reports on Form 8-K. The following reports on Form 8-K were filed either during the three months ended Dec. 31, 1999, or between Dec. 31, 1999, and the date of this report:
			Oct. 14, 1999, (Filed Oct. 14, 1999) Item 5. Other Events. Re: Disclosure of NSP and NRG's 1999 earnings outlook.
			Nov. 8, 1999, (Filed Nov. 8, 1999) Item 5. Other Events. Re: Disclosure of NSP's potential recovery levels of 1999 conservation incentives.
			Nov. 18, 1999, (Filed Nov. 18, 1999) Item 5. Other Events. Re: Disclosure of the Minnesota Public Utilities Commission's decision to reaffirm their denial of recovery of 1998 conservation incentives for NSP.
			Nov. 23, 1999, (Filed Nov. 23, 1999)—Item 5. Other Events. Item 7. Financial Statements and Exhibits. Re: Disclosure of the proposed business structure and officer team for Xcel Energy.
			Dec. 15, 1999, (Filed Dec. 22, 1999) Item 5. Other Events. Re: Disclosure of NSP's stipulated agreement with Minnesota Office of Attorney General and Minnesota Energy Consumers, related to support for NSP's proposed merger with NCE.
			Jan. 12, 2000, (Filed Jan. 13, 2000)—Item 5. Other Events. Item 7. Financial Statements and Exhibits. Re: Disclosure of NSP's 1999 earnings.
			Feb. 23, 2000, (Filed Feb. 23, 2000)—Item 5. Other Events. Re: Disclosure of NSP and NCE's filing of a Form U-1 associated with the merger approval process.
			March 3, 2000, (Filed Mar. 3, 2000)—Item 5. Other Events. Item 7. Financial Statements and Exhibits. Re: Disclosure of NSP's Dec. 31, 1999, year-ended financial statements and the related management's discussion and analysis.

103

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

			NORTHERN STATES POWER COMPANY
March 29, 2000			/s/ E J McIntyre Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

/s/ James J Howard Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)		/s/ E J McIntyre Vice President and Chief Financial Officer (Principal Financial Officer)
/s/ Roger D Sandeen Vice President and Controller (Principal Accounting Officer)		/s/ Douglas W Leatherdale Director
/s/ David A Christensen Director		/s/ W John Driscoll Director
/s/ Giannantonio Ferrari Director		/s/ Allan L Schuman Director
/s/ Margaret R Preska Director		/s/ A Patricia Sampson Director