NORTHERN STATES POWER CO /MN/
8-K, 2000-03-03
ELECTRIC & OTHER SERVICES COMBINED
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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:


    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.

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    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.

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Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:


    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 (see page 22)     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  
   
 
 
 

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    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.

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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

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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

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    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.

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    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.


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

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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

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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:

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


    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.

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    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:


    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:


    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.


    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:

13

    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.

14

    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:


    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.


    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

15

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.


    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:

16

17


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

18


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

19

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  
   
 
 

20

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

21


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

22

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

23

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

24

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 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:


    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.

25

    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:


    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.

26

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.

27

    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 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

28

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.

29

    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:


    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:


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

30

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:


    Compensation expense related to these awards was immaterial.

31

NOTES TO FINANCIAL STATEMENTS

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.

32

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 )      

33

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.

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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  
   
 
 
 

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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.

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    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.

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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

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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
   
 
 

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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

40

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.


    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

41

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

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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  
   
 

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    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.

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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.

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    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   150
    2000-2016   200
Winter exchanges to MH   2000-2014   150
    2000-2015   200
    2015-2017   400
    2018   200

    The cost of the 500-megawatt participation power purchase commitment is based on 80 percent of the costs of owning and operating NSP'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

46

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.

47

    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.


    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.

48

    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 (NOx) emission regulations affecting 22 states, including Wisconsin. The goal of the new regulations is to reduce NOx 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 NOx

49

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 NOx 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 NOxrules. NSP-Wisconsin believes that the EPA improperly included Wisconsin in the scope of the regulatory action and it improperly calculated potential emissions of NOx, reducing the allowable emission limits for the state.

    In 1999, the EPA was ordered by a federal appeals panel to suspend implementation of the NOx 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 NOx 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 NOx 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.

50

    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.

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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.

    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.

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    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 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.

    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.

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    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.


    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

54

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:


    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.

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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

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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.

57


REPORTS OF MANAGEMENT AND INDEPENDENT ACCOUNTANTS


REPORT OF MANAGEMENT

    Management is responsible for the preparation and integrity of NSP's financial statements. The financial statements have been prepared in accordance with generally accepted accounting principles and necessarily include some amounts that are based on management's estimates and judgment.

    To fulfill its responsibility, management maintains a strong internal control structure, supported by formal policies and procedures that are communicated throughout NSP. Management also maintains a staff of internal auditors who evaluate the adequacy of and investigate the adherence to these controls, policies and procedures.

    Our independent public accountants have audited the financial statements and have rendered an opinion as to the statements' fairness of presentation, in all material respects, in conformity with generally accepted accounting principles. During the audit, they obtained an understanding of NSP's internal control structure, and performed tests and other procedures to the extent required by generally accepted auditing standards.

    The Board of Directors pursues its oversight role with respect to NSP's financial statements through the Audit Committee, which is comprised solely of nonmanagement directors. The Committee meets periodically with the independent public accountants, internal auditors and management to assure that all are properly discharging their responsibilities. The Committee approves the scope of the annual audit and reviews the recommendations the independent public accountants have for improving the internal control structure. The Board of Directors, on the recommendation of the Audit Committee, engages the independent public accountants, subject to shareholder approval.

    Both the independent public accountants and the internal auditors have unrestricted access to the Audit Committee.

/s/ JAMES J. HOWARD   
Chairman of the Board, President
and Chief Executive Officer

/s/ EDWARD J. MCINTYRE   
Edward J. McIntyre
Vice President and Chief
Financial Officer

NORTHERN STATES POWER COMPANY
Minneapolis, Minnesota
January 31, 2000


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 generally accepted accounting principles. 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 generally accepted auditing standards, 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.


[SIGNATURE]

PricewaterhouseCoopers LLP
Minneapolis, Minnesota
January 31, 2000, except as to Note 2,
which is as of February 22, 2000


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