ML003698700

Submittal of 1999 Annual Report Including the Certified Financial Statements

ML003698700
Person / Time
Site:	Monticello, Prairie Island
Issue date:	03/23/2000
From:	Voth M Northern States Power Co
To:	NRC/OCIO/IMD/RMB
References
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Download: ML003698700 (61)

Text

Northern States Power Company Monticello Nuclear Generating Plant 2807 West County Road 75 Monticello, MN 55362 March 23, 2000 10 CFR 50.71(b)

U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555 MONTICELLO NUCLEAR GENERATING PLANT Docket No. 50-263 License No. DPR-22 PRAIRIE ISLAND NUCLEAR GENERATING PLANT Docket No.

50-282 License No.

DPR-40 50-306 DPR-60 Submittal of 1999 Annual Report Including the Certified Financial Statements In accordance with 10 CFR 50.71(b) and Item No. 70 in Regulatory Guide 10.1, enclosed are five (5) copies of our 1999 Annual Report, including the certified financial statements.

If you have any questions with regard to this information, please call Scott L. Weatherby at (612) 330-7643 or Marcus H. Voth at (763) 271-5116.

Sincerely, Marcus H. Voth Project Manager of Licensing Monticello Nuclear Generating Plant c: w/enclosure Regional Administrator-Ill, NRC Monticello NRR Project Manager, NRC Monticello Resident Inspector, NRC Prairie Island NRR Project Manager, NRC Prairie Island Resident Inspector, NRC c: w/o enclosure Minnesota Dept. of Commerce J E Silberg S L Weatherby 03/23/00 D311 J:\\LICENSE\\Periodic Reports\\1999 Annual Report Lotter.doc

NSP AND ITS MAJOR SUBSIDIARIES Northern States Power Company (NSP) I NSP is a major U.S. electric and natural gas utility with headquarters in Minneapolis, Minnesota. NSP and its wholly owned subsidiary NSP Wisconsin operate generation, transmission and distribution facilities providing electricity to about 1.5 million customers in Minnesota, Wisconsin, North Dakota, South Dakota and Michigan. The two companies distribute natural gas to about 500,000 customers in Minnesota, Wisconsin, North Dakota, South Dakota, Michigan and Arizona.

FINANCIAL HIGHLIGHTS Year Ended Dere hber 3 1 1999 1998 CA Changn Earnings per common share - diluted

$1.43

$1.84 (22.3)%

Dividends declared per share

$1.445

$1.425 1.4%

Stock price (close)

$19.50

$27.75 (29.7)%

Return on average common equity 8.7%

11.4%

Assets (millions)

$9 768

$7 396 32.0%

Book value per common share

$16.42

$16.25 1.1%

Electric and gas customers (thousands) 1 979 1 934 2.3%

Retail energy sales:

Electric (millions of kilowatt hours) 37 079 36 531 1.5%

Natural gas (billions of cubic feet) 91.1 85.2 6.9%

NRG Energy, Inc. (NRG) I NRG is a global leader in independent power production. The company specializes in the development, construction, operation, maintenance and ownership of power production and cogeneration facilities, thermal energy production and transmission facilities and resource recovery facilities. NRG has a high-quality portfolio of projects in the United States, Europe, Asia-Pacific and Latin America.

Seren Innovations, Inc. I Seren Innovations focuses on broadband, wireless and other com munication technologies. Through its Astound"' brand services, the company offers cable TV, high-speed Internet access and local and long distance telephone services over a new hybrid fiber-optic network.

Viking Gas Transmission Company Viking Gas Transmission Company operates an inter state natural gas pipeline located in Minnesota, North Dakota and Wisconsin.

ALTHOUGH WE BEGAN 2000 WITH MANY FACTORS IN OUR FAVOR, we were tremendously disappointed in our 1999 financial results and in the performance of our stock. I'm sure you were too. Our 1999 earnings were $1.43 per share, compared with $1.84 per share in 1998. Our stock price declined 29.7 percent from the beginning of 1999 to year-end.

We describe the reasons for our poor earnings and stock performances in the Management's Discussion and Analysis section beginning on page 19. Several one-time events were responsible for the earnings decline, which in turn affected the stock performance. Also significant to the stock price, however, were higher interest rates, which contributed to a 23 percent overall decline among utility stocks in general.

Without going into more detail, I want to say that the reasons for those performances are for the most part behind us. We are in a strong position to get back on track in 2000.

Our merger with New Century Energies (NCE) to form Xcel Energy Inc., for example, is ahead of schedule and could close during the second quarter. The merger will produce

$1.1 billion in net cost savings synergies over 10 years, half of which we expect to retain for shareholders. We are eager to launch this new venture, to say the least. I will serve as Xcel Energy's chairman for a year and NCE's Wayne Brunetti will be Xcel Energy's presi dent and CEO. We also have selected Xcel Energy's senior officers, a top-notch group of

experienced and talented individuals. Our business plans are in place and we are ready to hit the ground running once all the regulatory approvals are secure.

3 When the merger is complete, we anticipate that Xcel Energy will adopt a dividend payment level equivalent to the current NCE dividend payment lcvel adjusted for the exchange ratio. This would result in a dividend payment from Xcel Energy of $1.50 per share on an annual basis, a slight dividend increase for NSP shareholders.

From an operations perspective, NSP's utility system is strong, growing and enjoying the hard-earned support of our customers. Our electric and natural gas prices are low and will stay low in the coming competitive environment.

Our NRG Energy subsidiary has grow n into the big league of independent power producers worldwide, with 11,000 megawatts of generating assets. Of those assets, 81 percent are in the U.S. Substantial shareholder value has been created in NRG that is not reflected in our stock price. Publicly traded IPPs like NRG enjoy price-earnings ratios of 25 times or more.

We will explore ways to unlock that value for you this year. We expect NRG to continue its expansion and to provide a significant increase in earnings in 2000.

Seren Innovations, another NSP subsidiary, is a leader in the broadband communications industry with its proven strategy of selling significantly superior setvices, including cable I

television, high-speed Internet access and local and long distance telephone services.

Video-on-demand will become a new service offering this year. While subject to some uncertainties, Seren's five-year plan is to obtain a customer base of approximately 500,000 customers, with an annual revenue stream of $400 million. The industry has valued com panies with similar but inferior services and technology at about $5,000 per customer.

In other news of 1999, we accepted the resignation of NSP board member H. Lyman (Tad) Bretting, president and CEO of C.G. Bretting Manufacturing Company, Inc.

Tad resigned in December after serving on the board since March 1990. He had a distinguished tenure on our board, and we thank him for his service.

4 I'm sorry to tell you that Ed Theisen, retired NSP president, died June 11 of cancer. In his 40 years at NSP, Ed made many lasting contributions to our company. We will remember his honesty, optimism and gentle nature. Along with his family and many friends, we will truly miss him.

As I look ahead, I'm encouraged by several facts. Our growth platforms, including utility operations, NRG and Seren, are strong and in many ways unique. We expect our merger with NCE and the creation of Xcel Energy to provide a strong boost to your value. In fact, the rest of this report provides more reasons why NSP is a good investment.

We are looking forward to an exciting new beginning, and appreciate your trust and continued support.

Sincerely, James J. Howard Chairman of the Board President and Chief Executive Officer February 1, 2000

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financial setbacks in 1999, NSP continues to grow, thanks to excellent financial and operat ing fundamentals. The company's service territory is thriving, its cost structure is com petitive and its dividend increased for the 25th consecutive year.

NSP's core businesses are growing. In 1999, for example, NSP Gas purchased Natrogas, Inc.,

which includes 15,000 propane customers and 5,000 natural gas customers. NSP Energy Marketing also grew at a healthy pace, achiev ing wholesale sales of more than 6 million megawatt-hours of electricity.

Operating excellence is an NSP hallmark that is evident across the company. In 1999, NSP's combustion and hydroelectric plants generated more than 21.6 million megawatt hours of electricity and held up under trying conditions. During a heat wave in July, for example, those plants operated with a forced outage rate of just 1.9 percent, better than the company's five-year average. NSP's Monticello and Prairie Island nuclear plants safely gener ated a record 13.3 million megawatt-hours of electricity, surpassing the previous record set in 1995.

The company continues to make careful investments in its generating plants to keep them reliable, efficient and competitive. In 1999, crews at NSP's coal-fired plants over hauled the unit 3 turbine at the Sherco plant and upgraded controls at the High Bridge, Black Dog and Riverside plants. Having ben efited from a number of improvements over the years, the High Bridge plant marked its 75th anniversary in August.

In other measures of operating excellence, NSP Gas achieved the lowest costs for new gas service and new gas main in benchmark ing comparisons. By working closely with excavators, NSP Gas continues to reduce the incidents of damage to NSP's underground gas lines by excavating crews. NSP Electric met or exceeded all of its reliability perform ance measures and kept the electric system running during the heat wave with relatively few heat-related outages.

NSP also achieved several notable safety milestones in 1999. In Grand Forks, N.D.,

employees worked 12 years without a lost work day accident. Viking Gas Transmission received a safety award from the state of Wisconsin rec ognizing Viking's Chippewa Falls and Osceola districts for working 39 and 32 years, respec tively, without a lost work day accident.

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THE STRENGTH TO GROW BUSINESSES N>P HAS BLEEN AIM E 70 LElE\\'Lk\\GE its excellent operating skills to its nonregulated businesses, which are thriving. The value of these businesses, which is not yet reflected in the company's stock price, is an added benefit for NSP shareholders.

NRG Energy, Inc., an NSP subsidiary that is now the seventh largest independent power producer (IPP) in the world, is the best exam ple of the extra value shareholders receive by investing in NSP. In 1999, NRG purchased a number of power plants, tripling its ownership interests to approximately 11,000 megawatts of generating capacity.

In the Northeast region of the United States, NRG purchased 10 plants in New York, Massachusetts and Connecticut as well as four gas turbine plants. In 2000, NRG plans to purchase four plants and interests in two addi tional facilities from Conectiv of Wilmington, Del., for $800 million. These baseload facilities, which total 1,875 megawatts, add to NRG's existing Northeast holdings of more than 4,500 megawatts of generating capacity in the New York Power Pool and almost 2,500 megawatts in the New England Power Pool.

In Louisiana, NRG will purchase Cajun Electric Power Cooperative's 1,700 megawatts of fossil-fueled generation for $1.026 billion during 2000. In California, NRG is among the top four IPPs, with an interest in almost 2,800 megawatts. With solid footholds on both coasts, NRG is in a strong position to capture profits from emerging wholesale electric markets.

NRG also has a high-quality portfolio of proj-

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ects in Europe, Australia and Latin America.

In 2000, NRG plans to purchase the 665 megawatt, gas-fired Killingholme A power station in North Lincolnshire, England, for approximately $664 million.

Seren Innovations, Inc., a recognized E

telecommunications leader in the broadband market, provides high-speed Internet access, cable television and telephone services and soon 9

will offer video-on-demand. The company's use of superior technology and its ability to deliver all services with one connection put it in the enviable position of having customers knocking on its door. In 1999, the company expanded operations from St. Cloud, Minn.,

to communities in the San Francisco East Bay area and Colorado.

Viking Gas Transmission Co., an NSP sub sidiary that owns and operates an interstate natural gas pipeline, completed a 45-mile expansion that will increase capacity by 5 percent. Viking also initiated the Guardian Pipeline project in which the company and two partners plan to construct a gas pipeline to serve growing markets in northern Illinois and southeastern Wisconsin. In 1999, Viking increased its assets by 20 percent and received a favorable ruling from the Federal Energy Regulatory Commission, which allowed a 6 percent increase in revenues.

THE SATISFACTION OF OUR CUSTOME E RS ta 10 NSP continued several customer service enhancements in 1999, including expanding its automated meter reading system and con solidating its customer call centers into two locations. The company's investment in new technology to improve customer service and reliability proved especially worthwhile during the July heat storm, when NSP's energy man agement system helped system operators make critical decisions to keep the power flowing.

After announcing in June that it was Y2K ready, NSP experienced a seamless transition to the year 2000, reporting no Y2K outages.

NSP Gas implemented new rates that provide customers more choices in how they purchase natural gas from NSP. Advantage Service, NSP's appliance repair service, began selling appliances in 1999 and offering com petitive financing. In quarterly surveys, 87 per cent of Advantage Service customers rated the company's service as excellent or very good.

Perhaps the most gratifying measure of customer satisfaction comes directly from customer letters, phone calls and e-mails. "I can't compliment them enough," wrote one St. Paul gas customer about the NSP crew who worked through the night in sub-zero temperatures to install a new meter. "They got the problem resolved quickly and without hassle," said a Minnesota electric customer.

"They were friendly, courteous and caring."

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- L R LA\\RGL utilities, NSP is a low-cost producer of elec tricity, and its natural gas rates are among the nation's lowest. Those rates complement the company's excellent customer service, which NSP recognizes as critical to its future success.

If customers are satisfied today, they will be less likely to switch electricity providers when they are given a choice. By several measures, the company ranked high in customer satisfaction in 1999.

NSP was second in the nation for overall satisfaction among residential customers in a study by J.D. Power and Associates and Navigant Consulting, Inc. The study found that the key determinant of satisfaction in the electric utility industry is a provider's image, including such attributes as reputation, honesty, efforts to become more efficient and the ability to communicate changes. Other determinants of overall satisfaction are price and value, power quality and reliability, billing and the call center.

NSP's own customer satisfaction surveys also yielded strong results in 1999, with 94 percent of electric customers rating their overall satisfaction with NSP as excellent, very good or good. Employees working directly with customers turned in an outstanding per formance in all categories, including meter reading, billing, calls answered and credit.

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I operating procedures of both companies to determine best practices, which Xcel Energy will implement. Xcel Energy will remain committed to environmental stewardship and to the social and economic well-being of the communities it serves.

With headquarters and an operational center in Minneapolis, Minn., Xcel Energy also will maintain operational centers in Eau Claire, Wis., Denver, Colo., and Amarillo, Texas. The company's international presence includes operations in the United Kingdom, central Europe, Australia and South America.

In other efforts to prepare for a competitive energy market, NSP in 1999 agreed to join the Midwest Independent System Operator (ISO), a broad, regional transmission group that will take operational responsibility for the company's transmission assets. NSP believes the Midwest ISO is the most effective means presently available to enhance the competitive market for wholesale electricity.

COMvtPETITION IN THE RETAIL electric market is increasing as states across the nation allow customers to choose their elec tricity providers. Although Michigan is the only state in NSP's service territory to mandate competition so far, NSP has taken significant steps to prepare for a full-fledged competitive market. One of the most important efforts is the proposed merger with New Century Energies (NCE), a gas and electric utility in Denver, Colo., to form Xcel Energy Inc.

Operating in 12 states and serving 3 million electric customers and 1.5 million natural gas customers, Xcel Energy will have the size and scope necessary to compete with large national energy companies, and the financial strength and flexibility it needs to grow its regulated and nonregulated businesses. Including its subsidiaries, the new company will do business in at least 40 states and 15 countries. As a result, Xcel Energy will be able to provide shareholders with stronger returns on their investment and long-lasting value.

Customers also will benefit. Today, NSP and NCE customers enjoy competitively priced electricity and natural gas. Xcel Energy will be in a strong position to keep prices com petitive through the purchasing efficiencies and other economies of scale it will achieve.

To ensure a smooth transition and to make Xcel Energy a world-class energy company, NSP and NCE employees have reviewed the

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A LONG-TIME LEADER IN INNOVATION AS FAR BACK AS 1923. WHEN NSP was part of an experiment to bring electricity to rural areas, the company has been blazing trails in the energy industry. In the 1950s, NSP began exploring the commercial use of nuclear power, which became a safe, efficient and eco nomical source of generating electricity. In the 1970s, NSP was one of the first utilities to burn low-sulfur coal to reduce emissions. The company also installed pollution control equipment on its generating plants early on, putting it in compliance with the Clean Air Act regulations on sulfur dioxide well ahead of schedule. In the 1980s, NSP was experiment ing with wind generation, long before the state of Minnesota required its use.

Today, NSP is implementing an innovative new model for operating its nuclear generat ing plants. With increasing regulation and its related costs, nuclear plants find it challenging to remain competitive in a restructured energy market. In response, some utilities are selling their nuclear plants. Others are shutting down units prematurely.

NSP, which considers its nuclear plants to be extremely valuable assets, is taking a far different approach by forming the Nuclear Management Company (NMC) with three regional utilities: Alliant Energy, Wisconsin Electric Co. and Wisconsin Public Service Corp. Together, the utilities own seven nuclear units at five sites, which are capable of produc ing 3,650 megawatts of electricity.

Formed in February 1999, the NMC is working to become a nuclear operating com pany responsible for operating all five plants.

NSP's board of directors and the boards of the other utilities approved agreements to transfer the plants' operating licenses to the NMC.

Pending approval from the Nuclear Regulatory Commission and state regulators, the NMC could be operating the plants by mid-2000.

Although the NMC will operate the facili ties, NSP and the other parent companies will continue to own the plants and will retain the financial obligation for their safe operation, maintenance and decommissioning.

As the operator of seven nuclear units, the NMC will be able to share and employ best practices across the fleet of plants, achieve purchasing economies and capture many other benefits of scale. Best of all, the NMC concept ensures continued safe, reliable oper ations while enhancing the plants' value to shareholders.

A SINCERE COMMITMENT TO THE COMMUNITY CONTRIBUTING TO THE FINANCIAL and social well-being of communities in its service territory is a long-standing NSP commitment that will continue regardless of changes in the industry or the company.

NSP's contributions include corporate funding, economic development and envi ronmental efforts, as well as employee and retiree volunteerism.

In November, NSP celebrated its part in the restoration of the peregrine falcon, a bird that was taken off the endangered species list in 1999. Ten years ago, NSP began building nest boxes on the stacks of its power plants, where the peregrines could mate and raise their young. Almost 100 peregrines have hatched at NSP nest boxes.

On the economic development front, NSP encouraged Twin City Die Castings, a St. Paul-based foundry, to select Monticello, Minn., as the site for an expansion that eventually will result in 80 new jobs and an estimated $500,000 in annual electric revenues. In Wisconsin, the Nesd6 Corporation plans to build a new manufacturing plant in Eau Claire that will employ 125-200 people and will generate almost $1 million in gas and electric sales for NSP. An expansion at Andersen Windows in Menomonie, Wis.,

will create 250 new jobs and generate approx imately $360,000 in new gas and electric revenues. In Minot, N.D., ReliaStar opened a new service center, where 600 people now work, and Northwest Airlines announced plans to move its subsidiary MLT Vacations, Inc., to the city.

NSP's volunteerism was rewarded in 1999 when the company received the Judson Bemis Award for raising the most money during the Twin Cities UNCF walk-a-thon. The $28,000 that NSP walkers collected was the largest contribution by one company in the eight-year history of the walk-a-thon. NSP employees also raised more than $18,000 in Veterans' Day events that was given to veterans' homes.

Other volunteer efforts include tutoring and mentoring students, delivering Meals on Wheels and serving as camp counselors at Camp Sunrise, a camp for urban teenagers that NSP helped establish in 1974.

To ensure the availability of affordable housing in the area, NSP's subsidiary Eloigne Company has an ownership interest in more than 50 housing developments, providing more than 3,300 rental units to eligible tenants.

Eloigne is committed to investing in both family and senior housing that spans the social spectrum. In return, Eloigne's investments generate more than $9 million of tax credits annually, which are passed along to NSP

FINANCIAL STATISTICS SELECTED FINANCIAL DATA (Millions otollars. exeetv per share data)

Utility operating revenues Utility operating expenses Net income Earnings available for common stock Average number of common shares outstanding (000s)

Average number of common and potentially dilutive shares outstanding (000s)

Earnings per average common share:

Basic Diluted Dividends declared per share Total assets Long-term debt Ratio of earnings to fixed charges 1999

$2 869

$2 526

$224

$219 153 366 1998 1997 1996 1995

$2819

$2734

$2654

$2569

$2455

$2372

$2288

$2223

$282

$237

$275

$276

$277

$226

$262

$263 150502 140594 137121 134646 153443 150743 140870 137358 134832

$1.43

$1.43

$1.445

$9 768

$3 453 2.1

$1.84

$1.61

$1.91

$1.96

$1.84

$1.61

$1.91

$1.95

$1.425

$1.403

$1.373

$1.343

$7396

$7 144

$6637

$6229

$1 851

$1 879

$1 593

$1 542 3.0 2.9 3.8 3.9 FINANCIAL STATISTICS Return on average common equity (a)

Dividends as percent of earnings Dividends as percent of book value Utility capital expenditures (millions)

Internally generated utility funds (W)

Cash dividend coverage AFC as percent of earnings per share Effective tax rate Capitalization:

Common equity Preferred equity and securities Debt (W)

Total Accumulated depreciation as a percent of utility plant Depreciation expense as a percent of average depreciable utility plant 1999 1998 1997 1996 1995 8.7%

11.4%

10.2%

12.5%

13.4%

101.4%

77.7%

89.4%

71.5%

68.5%

8.9%

9.0%

9.1%

9.3%

9.5%

$462

$411

$397

$387

$386 80%

114%

109%

81%

94%

3.0 3.2 3.3 2.8 3.1 2.8%

5.7%

7.3%

7.2%

6.5%

22.8%

27.1%

29.0%

34.8%

35.6%

34.5%

4.1%

61.4%

47.3%

46.7%

46.5%

48.4%

5.8%

7.9%

5.2%

5.7%

46.9%

45.4%

48.3%

45.9%

100.0%

100.0%

100.0%

100.0%

100.0%

50.3%

49.2%

47.6%

46.0%

44.2%

3.83%

3.77%

3.78%

3.68%

3.64%

(a) 13-month average (b) Percent of utility capital expenditures that could befinanced by internally generated utilit, fiunds, excluding allowance for fiinds used during construction (AFC) and after dividends (c) Includes sbort-term debt, currentportion oflong-term debt and AVRG project-secured debt ofapproxinatel), $1 billion, as shown in the Statements of Capitalization 18

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.

P I.IANItIAA In PrCTTWr AN)in I HRJITR Because of several significant charges and adverse weather condi tions (both are discussed later), 1999 earnings declined and NSP fell short of some of its financial objectives. This decline in earn ings is not representative of NSP's continuing operational and financial strength.

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

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

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

• AA-by Fitch IBCA 0 AA by Standard & Poors o Aa3 by Moody's Investors Service The three rating agencies placed NSP's bond ratings under review upon announcement of its merger with NCE. These ratings and the review reflect the views of rating agencies, which can provide an explanation of the significance. A security rating is not a recommen dation 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.

BIJINFSS 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 I 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 acquisi tions have enabled its earnings to grow from 16 cents per share in 1997 to 37 cents per share in 1999. NRG's long-term goal is to increase its earnings by an average of 25 percent per year. During 1999, NRG completed more than $1.6 billion of asset acquisitions, increasing its generation capability by more than 7,500 megawatts.

During 2000, NRG expects to spend approximately $2.7 billion to acquire or develop more than 6,000 megawatts of generating facilities.

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

Create an Independent Nuclear Company I With increasing regula tion and associated costs in the nuclear industry, NSP believes the best way to enhance NSP's nuclear assets is to combine our opera tions 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 ser vices to member companies.

Expand Ene?g, Marketing I To enhance NSP's position in the increasingly competitive electric market, NSP has expanded its whole sale energy marketing efforts by establishing an Energy Marketing function. Energy Marketing is responsible for meeting the require ments 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 I 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 NSPs 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 com pleted by the middle of 2000.

Develop Seren I 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 I 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 I EMI is narrowing its focus to concen trate on retrofitting and upgrading customer facilities for greater energy efficiency.

Manage NSP' Entire Business as a Portfolio I 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 pro posed merger with NCE, limit NSP's ability to divest assets for a period of time.

0 19

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

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate,"" estimate,"

"expect," "objective," "outlook," "possible," "potential" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:

"* general economic conditions, including their impact on capital expenditures

"* business conditions in the energy industry

"* competitive factors

"* unusual weather

"* changes in federal or state legislation

"* regulation

"* the higher risk associated with NSP's nonregulated businesses as compared with NSP's regulated business

"* currency translation and transaction adjustments

° issues relating to Year 2000 remediation efforts

• regulatory delays or conditions imposed by regulatory agencies in approving the proposed merger with NCE

° the items described under "Factors Affecting Results of Operations"

• the other risk factors listed from time to time by NSP in reports filed with the Securities and Exchange Commission (SEC),

including Exhibit 99.01 to NSP's 1999 report on Form 10-K Proposed Business Combination I 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 divi dend 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.

RFSUITS OF OPFRATIONS 1999 Compared with 1998 and 1997 1 NSP's earnings per share for the past three years were as follows:

(Earnins per S're - Dilutred)

Regulated utility operations (excluding Primergy costs)

Nonregulated operations (see page 22)

CellNet investment write-down Subtotal excluding Primergy costs Write-off of Primergy merger costs TOTAL 1909 IG OR 1007

$1.26

$1.58

$1.62 0.22 0.26 0.11 (0.05)

$1.43

$1.84

$1.73 (0.12)

$1.43

$1.84

$1.61 a

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Conservation Incentive Recovery 1998 1 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 con servation. 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 1 At the end of 1999, the MPUC had not approved a conservation plan for 1999 or subse quent 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 incen tives that could be earned is approximately $10 million, with the actual incentive dependent on performance compared with conser vation 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 I 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.

MANAGEMENT'S DISCUSSION AND ANALYSIS Loss on Marketable Securities I During 1999, NSP recorded pretax charges of approximately $14 million, or 5 cents per share, for a valu ation write-down on its investment in the publicly traded common stock of CelINet Data Systems, Inc. In October 1999, CellNet announced it was experiencing financial difficulties and was contem plating 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 approxi mately $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.

REGIJI ATF)

IJTII ITY OPERATING RFSU1,TS Electric Revenues I The following table summarizes the principal reasons for the electric revenue changes during the past two years:

(Millions oIdollarO 1 9 9 9 vs. 199 1998 v. 1997 Retail sales growth (excluding weather impact)

Estimated impact of weather on retail sales volume Sales for resale Conservation incentive accrual adjustments Fuel cost recovery Rate changes Transmission and other TOTAL REVENUE INCREASE

$35

$ 63 (2) 25 (78) 47 5

3 47 4

19 2

3 6

$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.

ico*,., tone

,ooo..,. to7 Residential Commercial and industrial Total retail Sales for resale TOTAL ELECTRIC SALES na = not applicable Weather Actual Normalized 2.4%

2.5%

1.1%

1.2%

1.5%

1.6%

6.7%

na 2.3%

na Weather Actual iVormalizrd 3.4%

3.7%

3.3%

3.1%

3.3%

3.3%

35.3%

na 7.1%

na Retail electric sales accounted for 93 percent of NSP's electric rev enue 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 NSPs whole sale energy marketing operations.

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

Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and pur chased 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 NSPs power plants operating at maxi mum 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 fill recovery, these unusu ally 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:

(Millionc ofdalla )

1999 ia. 1998 1 998 vm 1997 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 I The following table summarizes the principal reasons for the gas revenue changes during the past two years:

(Millions of do/larn)

Sales growth (excluding weather impact)

Estimated impact of weather on firm sales volume Purchased gas adjustment clause recovery Rate changes Black Mountain Gas Company acquisition Transportation and other TOTAL REVENUE INCREASE (DECREASE) 1999Y.

199IR 1990R,, 1997

$7

$7 20 (46)

(11)

(40) 9 6

(2) 6

$15

$(58) c at tIn/la rcI Electric revenue Fuel for electric generation Purchased and interchange power ELECTRIC MARGIN 1999 1998 1997

$2397

$2362

$2218 (319)

(311)

(310)

(454)

(378)

(286)

$1 624

$1 673

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

Total firm Interruptible Total retail Transportation and other Viking (wholesale transportation)

TOTAL GAS SALES AND DELIVERY na = not applicable 1999 v 1992 199R vft 1997 Weather-Weather Actual Normg/lized Actual iormalizged 8.6%

1.4%

(13.1)%

2.9%

2.3%

na (10.4)%

na 6.9%

na (12.4)%

na (11.8)%

na 33.4%

na (0.9)%

na 2.8%

na 1.1%

na (1.5)%

na 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 MIargin I As shown in the following table, gas margin equals gas revenue less the cost of gas sold.

(Actihlios ni dal/or, Gas revenue Cost of gas purchased and transported GAS MARGIN Expenses increased in 1998 by $48.3 million, or 7.2 percent, com pared 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 andAmortization I 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 equip ment with relatively short depreciable lives.

NONJGPFRATING IJTII ITY ITFMS Utility Financing Costs I Interest costs for NSPs 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.

Allowancefor Funds Used During Construction (AFQ I 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 I 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.

1999 1992 1997 NONRFGUIATFD BUSINFSS RFSJITS

$472

$457

$515 A description of NSPs primary nonregulated businesses and their earnings contribution is summarized below.

(278)

(267)

(331)

$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 recov ery 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:

(AilLoni ot dol/ar) 199 Retail and transportation sales growth (excluding weather impact)

Estimated impact of weather on firm sales volume Rate changes Black Mountain Gas Company acquisition Other TOTAL GAS MARGIN INCREASE 9 7).1998 1998 Vý.1997

$4

$7 6

(16) 1 9

4 (7) 2 o NRG is involved in independent power production, commercial and industrial heating and cooling, and energy-related refuse-derived fuel production.

0 EMI is an energy services company.

" Eloigne invests in affordable housing.

° Seren provides broadband communication services.

CONTRIBUTION TO NSPS 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 TOTAL (0.05)

$0.17

$0.26

$0.11

$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.

NRG I NRCs 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 K(ales o*,ointh a

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MANAGEMENT'S DISCUSSION AND ANALYSIS 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 devel opment, and increased interest expenses. Also, equity earnings were affected by several other factors, including a currency transaction adjustment relating to the Kladno project and a decrease in earnings from NEO, NRG's landfill gas affiliate.

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

$9 million, or 4 cents per share.

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

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

EMI I EMI's losses for 1999 were greater than 1998, due to the write-off of goodwill associated with two acquisitions, as previ ously 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 I Eloigne's earnings grew in 1999 and 1998 due to new investments in affordable housing projects.

Seren I 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 OPFRATIONS 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 sig nificant 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 I 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 non regulated 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 regula tory 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 regula tion. In addition to a potential write-off of regulatory assets and liabilities, deregulation and competition may require recognition of certain "stranded costs" not recoverable under market pricing. NSP currently does not expect to write off any "stranded costs" unless market price levels change, or cost levels increase above market price levels. See Notes I and 9 to the Financial Statements for fur ther discussion of regulatory deferrals.

Meiger SettlementAg©eements I 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 cus tomers, to meet various quality standards and to certain provisions affecting the regulatory oversight of Xcel Energy.

Competition I The Energy Policy Act of 1992 has been a catalyst for comprehensive and significant changes in the operation of elec tric 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 23

MANAGEMENT'S DISCUSSION AND ANALYSIS 0

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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 avail ability and pricing information on an electronic bulletin board.

NSP has made open access transmission tariff filings and com pliance 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 OperationsI During 1999, NSP joined the Midwest ISO, a FERC-approved Regional Transmission Organization (RTO).

This action commits the NSP transmission system to control by the Midwest ISO and ensures transmission operations in compliance with FERC Order No. 888. Recent developments include:

"The Midwest ISO intends to commence operations in 2001.

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

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

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

" During 1999, NSP, Wisconsin Electric Power Co., Wisconsin Public Service Corp. and Alliant Energy established an NMC to improve plant performance and reliability, strengthen oper ational efficiency, maintain high safety levels and reduce costs.

The four companies operate seven nuclear units at five sites, with a total generation capacity exceeding 3,650 megawatts.

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

The request to transfer operating licenses requires approval from federal regulators, including the NRC.

Used Nuclear Fuel Storage and Disposal I 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 gen erating 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 dis cussed 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) 1 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 oper ations, 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.

MANAGEMENT'S DISCUJSSION AND ANALYSIS En viromnnentalMatters I 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 dis charges 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, NRCs recent acquisition of generation facilities will tend to increase nonutility costs for environmental compliance.

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

• $32 million in 1999

• $32 million in 1998

• $31 million in 1997 NSP's utility operations expect to spend approximately $35 million per year for 2000-2004. However, the precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are currently unknown.

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

o $39 million in 1999

• $21 million in 1998

, $19 million in 1997 NSP expects to incur approximately $24 million in capital expendi tures 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 envi ronmental contingencies.

Weather I 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 recov erable. Unseasonably mild weather reduces electric and gas sales.

The following summarizes the estimated impact on NSP's earnings due to temperature variations from historical averages.

"* Weather in 1999 decreased earnings by an estimated 8 cents per share.

"* Weather in 1998 decreased earnings by an estimated 11 cents per share.

"* Weather in 1997 decreased earnings by an estimated 6 cents per share.

Impact of ionregulared hvestments I

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

"* competition, operating risks, dependence on certain suppliers and customers, and domestic and foreign environmental and energy regulations;

"* partnership and government actions and foreign government, political, economic and currency risks; and

"* development risks, including uncertainties prior to final legal closing.

Some of NRG's project investments (as listed in Note 10 to the Financial Statements) consist of minority interests, which may limit NRG's financial risk, but also limit NRG's ability to control the development or operation of the projects. In addition, signifi cant 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 Mlarket Risk I 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 I 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 approxi mately $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 market ing 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.

25

MANAGEMENT'S DISCUSSION AND ANALYSIS

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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 I 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 regu lation are expected to minimize or eliminate any impact on operating expenses and earnings from this future accounting change. For fur ther discussion of the expected impact of this change, see Note 13 to the Financial Statements.

In June 1998, the FASB issued SIAS 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 earn ings or deferred as a component of other comprehensive income, depending on the intended use of the derivative, its resulting desig nation 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.

LtOi LQITYN_C APITA REMULQRCES 1999 Financing Requirements [ NSP's need for capital funds primar ily is related to the construction of plant and equipment to meet the needs of electric and gas utility customers and to fund equity com mitments or other investments in nonregulated businesses. In 1999:

Total utility capital expenditures were $462 million. Of that amount, $367 million related to replacements and improvements of NSP's electric system and nuclear fuel, and

$67 million involved construction of natural gas facilities.

NSP companies (mainly NRG) invested approximately

$1.9 billion for equity interests in and loans to nonregulated projects for the acquisition of generating assets and for addi tions to nonregulated property.

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

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

NSP's goal for its pretax interest coverage ratio for utility operations is 3.5-5.0. The utility pretax interest coverage ratio, excluding AFC, was 3.2 in 1999, 3.8 in 1998 and 3.6 in 1997.

Internally generated funds from utility operations could have provided financing for approximately 80 percent of NSP's utility capital expenditures for 1999 and approximately 95 percent of the $2.0 billion in utility capital expenditures incurred from 1995-1999. The pretax interest coverage ratio, excluding AFC, for all NSP operations was 2.1 in 1999, 2.9 in 1998 and 2.8 in 1997.

o External financing - NSP's short-term debt availability and usage is described in Note 2 to the Financial Statements. In general, short-term borrowings are used to provide temporary financing, mainly for NSP-Minnesota and NRG, utility capital expenditures, nonregulated projects and other short-term cash needs. NSP's long-term debt and capital stock activity are shown on the Statements of Capitalization and Stockholders' Equity. These sources are used to provide permanent financ ing for both regulated and nonregulated business activities.

The 1999 nonregulated asset acquisitions, property additions and equity investments by NSP's subsidiaries were primarily financed by the issuance of subsidiary debt and equity contribu tions from NSF. 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 I 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 approxi mately $50 million for natural gas facilities. In addition to utility capital expenditures, expected financing requirements for 2000-2004 include approximately $1 billion to retire long-term debt and fund principal maturities.

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

NRG expects to invest approximately $2.7 billion in 2000 and approximately $4.7 billion for 2000-2004 for nonregulated projects and property, which include acquisitions and project investments. NRG's capital requirements may vary signifi cantly. 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.

26

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

NSP and its subsidiaries continue to evaluate opportunities to enhance shareholder returns and achieve long-term financial objec tives through investments in projects or acquisitions of existing businesses. These investments could cause significant changes to the capital requirement estimates for nonregulated projects and prop erty. 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 I NSP expects to meet future financing requirements by periodically issuing long-term debt, short-term debt, common stock and preferred securities to maintain desired capitaliza tion ratios. Over the long term, NSPs equity investments in and acquisitions of nonregulated projects are expected to be financed at the nonregulated subsidiary level from internally generated finds or the issuance of subsidiary debt. Financing requirements for the non regulated projects, in excess of equity contributions from partners, are expected to be fulfilled through project or subsidiary debt.

Decommissioning expenses not funded by an external trust will be financed through a combination of internally generated funds, long-term debt and common stock.

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

Internal funds - Internally generated funds from utility operations are expected to equal approximately 85 percent of anticipated utility capital expenditures for 2000 and approxi mately 95 percent of the anticipated utility capital expenditures for 2000-2004. Because NRG has been reinvesting foreign cash flows in operations outside the United States, the equity income from foreign investments is not fully available to provide operating cash flows for domestic cash require ments such as payment of NSP dividends, domestic capital expenditures and domestic debt service.

Short-term debt - NSP has received regulatory approval for up to approximately $1.5 billion in short-term borrowing levels.

NSP credit lines (as discussed in Note 2 to the Financial Statements) make short-term financing available in the form of bank loans, letters of credit and support for commercial paper.

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

NRG debt - In December 1999, NRG filed a shelf registration with the SEC to issue up to $500 million of unsecured debt.

NRG expects to issue debt under this shelf during 2000 for general corporate purposes, which may include financing development and construction of new facilities, additions to working capital and financing capital expenditures and pending or potential acquisitions. In addition to NRG corporate debt, NRG Northeast Generating LLC (N.E. Generating), a wholly owned subsidiary of NRG, issued $750 million of bonds in February 2000 to pay down short-term borrowings and reduce NRG's corporate debt issued to fund N.E.

Generating (see Note 2).

Common stock - NSP's Articles of Incorporation authorize an additional 194.3 million shares of common stock in excess of shares issued at Dec. 31, 1999. In 1999, NSP filed registration statements with the SEC to allow for the sale of up to 1.9 million shares of newly issued common stock under NSP's Dividend Reinvestment and Stock Purchase Program (DRSPP) and Executive Long-Term Incentive Award Stock Plan. NSP plans to issue new shares for its DRSPP, Employee Stock Ownership Plan (ESOP) and Executive Long-Term Incentive Award Stock Plan in 2000.

NSP filed its proposed 2000 Capital Structure and Financing Plan with the MPUC in November 1999. In its filing, NSP proposed that if the completion of its merger with NCE is timed as currently anticipated, NSP will be recapitalized as a subsidiary of Xcel Energy. If completion of the merger appears to be delayed, NSP may issue equity or an equity related security in the first half of 2000.

Preferred stock - NSP's Articles of Incorporation authorize the maximum amount of preferred stock that may be issued.

Under these provisions, NSP could have issued all $595 million of its remaining authorized, but unissued, preferred stock at Dec. 31, 1999, and remained in compliance with all interest and dividend coverage requirements.

27

CONSOLIDATED STATEMENTS OF INCOME Yar Ended Deceniber 31

,LYZZ LZ 199 f-15o1saild ({fdoi/ar's, cxcepýt p/eC; sbare data)

UTH l1Y O!PFRAI ING RI VFNU[FS Electric: Retail Sales for resale and other Gas Total UTILI IY OI LRAING I XI NSES Fuel for electric generation Purchased and interchange power Cost of gas purchased and transported Other operation Maintenance Administrative and general Conservation and energy management Depreciation and amortization Property and general taxes Income taxes Total Utility operating income 01II I[1 INCO\\ME (I \\XI'lN'. )

Income from nonregulated businesses - before interest and taxes Allowance for funds used during construction - equity Write-down of investment in CellNet stock Primergy merger costs Other utility income (deductions) - net Income taxes on nonregulated operations and nonoperating items - benefit Total Income before financing costs FINANCING CO\\1S Interest on utility long-term debt Other utility interest and amortization Nonregulated interest and amortization Allowance for funds used during construction - debt Total interest charges Distributions on redeemable preferred securities of subsidiary trust Total financing costs NIT INCOMI Preferred stock dividends and redemption premiums ARNIN GS A\\AI IA B1 I[ FO[R COMONI0N S MOCK Average number of common shares outstanding (000s)

Average number of common and potentially dilutive shares outstanding (000s)

I.ARNI NGCS P RI AVEAG F COMM NI\\ON SI ARIR I AININGS PlL A\\':IS,\\GF COMIMON S1ARIU Common dividends declared per share BAS I C DI LUILD 319 193 454487 278 240 401 968 178 594 127 427 60 180 355 704 222 446 127 293 311 368 377 907 267 050 392 054 181 066 150 078 71 134 338 225 220 620 145 383 309 999 286 239 331 296 368 545 164 542 141 802 70 939 325 880 227 893 144 855 2525 532 2454 885 2371 990 343 479 364 289 361 756 79439 51 171 12078 162 8 509 6401 (14 063)

(29 005)

(9 483)

(3 697)

(2 886) 61 011 40588 48 145 117066 96571 34 733 460 545 460 860 396 489 102843 104 171 101250 25677 11 612 19063 97854 54261 34627 (5915)

(7307)

(10208) 220459 162737 144732 15750 15750 14437 236209 178487 159 169 224 336 282 373 237 320 5292 5548 11 071

$ 219044

$ 276825

$ 226249 153366 150 502 140594 153443 150743 140870 1.43 1.84 1.61 1.43 1.84 1.61 1.445 1.425 1.403 Se.Votes to iNnanial Sratmnents

$2 169 296 227 800 471 915 2869011

$2 152221 210 130 456 823 2819 174

$2 054 473 164 077 515 196 2 733 746 2

28 rNNN

CONSOLIDATED STATEMENTS OF CASH FLOWS I QQ)

I 99R

!997 (Thnua....,I¢o,

,Ih.

CASH FLOWS FR OM OPERATING ACTIVI I ES Net income Adjustments to reconcile net income to cash from operating activities:

Depreciation and amortization Nuclear fuel amortization Deferred income taxes Deferred investment tax credits recognized Allowance for funds used during construction - equity Undistributed equity in earnings of unconsolidated affiliates Conservation incentive adjustments - noncash Write-downs of EMI goodwill and CellNet investment Write-off of prior year Primergy merger costs Cash provided by (used for) changes in certain working capital items (see below)

Cash provided by changes in other assets and liabilities NEI CASH PRO OVIDED BY OPERATING ACIIVI 1ES CASH I LOWS FROM [NVEST I NG ACT I VITI LS Capital expenditures:

Nonregulated property additions and asset acquisitions Utility plant additions (including nuclear fuel)

Increase (decrease) in construction payables Allowance for funds used during construction - equity Investment in external decommissioning fund Equity investments, loans and deposits for nonregulated projects Collection of loans made to nonregulated projects Other investments - net NET CASH USED FOR INVEST ING ACIVII IES CASH FLOWS FROMl FINANCING ACTIVI I IES Change in short-term debt - net issuances (repayments)

Proceeds from issuance of long-term debt - net Repayment of long-term debt, including reacquisition premiums Proceeds from issuance of preferred securities-net Proceeds from issuance of common stock - net Redemption of preferred stock, including reacquisition premiums Dividends paid NET CASH PROVIDED BY (USED FOR) FINANCING ACTIVITIES NELi INCREASE (DECREASE) IN CASH AND CASH EOJUIVALENTS Cash and cash equivalents at beginning of period CASH AND CASH EQUIVALENTS AT END OF PERIOD CASH PROVIDED BY [USED FOR CHANGES IN CERTAIN WORKING CAPITAL II EMS Customer accounts receivable and unbilled utility revenues Materials and supplies inventories Payables and accrued liabilities (excluding construction payables)

Other N ET SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORM4AT ION Cash paid during the year for:

Interest (net of amount capitalized)

Income taxes (net of refunds received)

$ 224336

$282373

$237320 423 807 50 056 (18 907)

(9417)

(162)

(27 956) 71 348 31 346 (80 649) 17 348 379 397 43 816 (1 017)

(9 432)

(8 509)

(22 753)

(13 673) 51 863 358 928 40 015 (5 902)

(10 061)

(6401)

(5 364) 25 289 36 117 19 844 681 150 702065 689785 (1698414)

(44918)

(195 528)

(462054)

(411 113)

(396605)

(2 604) 5 270 2 563 162 8509 6401 (39 183)

(41 360)

(41 261)

(176 207)

(234 214)

(395 495) 81 440 109 530 87 128 (16 545) 1 307 (15 692)

(2 313 405)

(606 989)

(948 489) 1 205 894 (20 522)

(108 023) 859718 290626 299779 (249 371)

(135 183)

(141 681) 193 315 55 127 72348 267 965 (95 000)

(41 278)

(225 509)

(219 746)

(207 726) 1 645 859 (107 477) 262 351 13604 (12401) 3647 42364 54765 51 118 55968

$ 42364

$ 54765

$ (106692)

$ (1 583)

$ 47745 (22 228)

(5 385)

(8 547) 73 136 7 845 (7342)

(24865)

(14 550) 4261

$ (80649)

$(13673)

$ 36 117

$ 201276

$148275

$144062 65 121

$ 74005

$113009 See Nlotes to Financial Statements 29 V11-1.

V1111111

ý' I

CONSOLIDATED BALANCE SHEETS aiozasanefdosard ASSETS UTILITY PLANT Electric - including construction work in progress: 1999, $119,944; 1998, $120,095 Gas Other Total Accumulated provision for depreciation Nuclear fuel - including amounts in process: 1999, $13,708; 1998, $16,744 Accumulated provision for amortization Net utility plant CURRENT ASSETS Cash and cash equivalents Customer accounts receivable - net of accumulated provisions for uncollectible accounts: 1999, $8,442; 1998, $5,176 Unbilled utility revenues Other receivables Materials and supplies inventories - at average cost:

Fuel Other Prepayments and other Total current assets OTH ER ASSETS Nonregulated property-net of accumulated depreciation: 1999, $203,767; 1998, $122,445 Equity investments in nonregulated projects External decommissioning fund and other investments Regulatory assets Notes receivable from nonregulated projects Long-term prepayments, deferred charges and receivables Intangible assets - net of accumulated amortization Total other assets TOTAL LIABILITIES AND EQUITY CAPITALIZATION (SEE CONSOLIDATED STATEMENTS OF CAPITALIZATION)

Common stockholders' equity Preferred stockholders' equity Mandatorily redeemable preferred securities of subsidiary trust Long-term debt Total capitalization CURRENT LIABILITIES Long-term debt due within one year Other long-term debt potentially due within one year Short-term debt - utility Short-term debt - nonregulated Accounts payable Taxes accrued Interest accrued Dividends payable on common and preferred stocks Accrued payroll, vacation and other Total current liabilities OTHER LIABILITIES Deferred income taxes Deferred investment tax credits Regulatory liabilities Postretirement and other benefit obligations Other long-term obligations and deferred income Total other liabilities COMNMITMENTS AND CONTINGENT LIABILITIES (SEE NOTES 13 AND 141 TOTAL 30 Drrpm.r e3 1

199*9 1992_

$7430686

$7 199843 952 131 884 182 375 058 365 101 8757875 8449 126 (4409 151)

(4 155 641) 1 026 063 975 030 (923336)

(873281) 4451451 4395234 55 968 370 270 144 261 58 680 42 364 253 559 139 098 105 116 59 600 58 806 231 503 110267 113 524 44855 1 033 806 754 065 2 086 476 282 524 1 047 248 862 596 561 682 479 402 248 127 331 940 66876 106427 158 096 88 194 113969 95915 4 282 474 2 246 998

$9767731

$7396297

$2557530

$2481 246 105 340 105 340 200 000 200 000 3453 364 1 851 146 6316234 4637732 153231 227600 141 600 141 600 420443 114273 378716 125557 321 382 271 799 172059 170274 49 327 38 836 57 523 55 650 131 855 86673 1826136 1232262 811 638 814983 118582 128444 461 569 372239 143905 129514 89667 81 123 1 625 361 1 526303

$9767731

$7396297 See Notes to Financial Statemenwts

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY CLDW-atLadml'a1,14r BALANCE AT DEC. 31. 1996 Net income Currency translation adjustments Comprehensive income for 1997 Dividends declared:

Cumulative preferred stock Common stock Premium on redeemed preferred stock Issuances of common stock - net Tax benefit from stock options exercised Repayment of ESOP loan (a)

BALANCE AT DEC. 31, 1997 Net income Unrealized loss from marketable securities, net of tax of $4,417 Currency translation adjustments Comprehensive income for 1998 Dividends declared:

Cumulative preferred stock Common stock Issuances of common stock - net Pooling of interests business combinations Tax benefit from stock options exercised Loan to ESOP to purchase shares (a)

Repayment of ESOP loan (a)

BALANCE AT DEC. 31, 1998 Net income Recognition of unrealized loss from marketable securities, net of tax of $4,417 Currency translation adjustments Comprehensive income for 1999 Dividends declared:

Cumulative preferred stock Common stock Issuances of common stock - net Pooling of interests business combination Tax benefit from stock options exercised Repayment of ESOP loan (a)

BALANCE AT DEC. 31, 1999 Retained P'IaYLdeings

$345318

$466060

$1 340799 237 320 Acc.

Shares Held Coma

$(19 091)

(9 923)

(202 173)

(1 148) 27774 240 112 1 009 8 558

$373 092

$707 181

$1 364 875

$(10 533) 282 373 enmulated Other 7btal trehensive Stockholders'

$ 2794

$2 135 880 237 320 (65 681)

(65 681) 171 639 (9 923)

(202 173)

(1 148) 267 886 1 009 8 558

$(62 887) $2 371 728 282 373 (6416)

(6416)

(19711)

(19711) 256 246 (5 548)

(5 548)

(215069)

(215069) 8 650 66 294 74 944 6065 6065 850 850 (15000)

(15000) 7030 7030

$381742

$774 325

$1432696

$(18503)

$(89 014) $2 481 246 224 336 224 336 6416 7 128 7 582 46 652 (5 292)

(222 092) 4 599 58 6416 7 128 237 880 (5 292)

(222 092) 54 234 4 599 58 6897 6897

$389 324

$821 035

$1434247

$(11606)

$(75 470) $2 557 530 (a) Did not affect NSP cash flows See Notes to Financial Statements 31 m

gd_.oa*lazs.J

CONSOLIDATE[D STATEMENTS OE CAPIT ALIZAT ION I  hn,,,,n,,I,,nck,//,n CONIM()N 'IOCKIIOI. DLRI IA I).UI Y Common stock - authorized 350,000,000 shares of $2.50 par value; issued shares: 1999, 155,729,663; 1998, 152,696,971 Premium on common stock Retained earnings Leveraged common stock held by Employee Stock Ownership Plan (ESOP) shares at cost: 1999, 392,325; 1998, 641,884 Accumulated other comprehensive income 101AL CO(tMMON SIOCKHI()1)IIR LQ.UIIY CU \\1 0 LAVII

\\.

PR lI L RI D 0

IC K - 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 4.08 series, 150,000 shares 4.10 series, 175,000 shares 4.11 series, 200,000 shares 4.16 series, 100,000 shares 4.56 series, 150,000 shares Total Premium on preferred stock 101 AL IM I1I 1:RL1 SIOCKIIOLDI.RS' PL[UI IY M\\AN DAI\\IORILY RI DLLMI\\AIP[

PIRLI: LIRRI S)CL-R.IIII[FS Of UBSIDIR) Y 1

RI USI holding as its sole asset junior subordinated deferrable debentures of NSP-Minnesota 7 7s% series, 8,000,000 shares due Jan. 31, 2037 (See Note 8)

LONG-I LM DHBI First Mortgage Bonds - NSP-Minnesota Series due:

Feb. 1, 1999, 5Y2%

Dec. 1, 2000, 5X%

Oct. 1, 2001, 77%

April 1, 2003, 67%

Dec. 1, 2005, 67*%

Dec. 1, 1999-2006, 6.00%-6.75%

Dec. 1, 1999-2006, 3.50%-4.10%

March 1, 2011, Variable Rate July 1, 2025, 7Ys%

April 1, 2007, 6.80%

March 1, 2019, Variable Rate Sept. 1, 2019, Variable Rate March 1, 2003, 57s%

March 1, 2028, 6Y%

Total Less redeemable bonds classified as current (See Note 3)

Less current maturities Net

$ 389 324 821 035 1 434 247

$ 381 742 774 325 1 432 696 (11 606)

(18 503)

(75470)

(89014)

$2557 530

$2481 246 27500 27500 15000 15000 17500 17500 20 000 20 000 10000 10000 15 000 15000 105000 105000 340 340

$ 105340

$ 105340

$ 200000

$ 200 000

$ 100000 150 000 80 000 70 000

$ 200 000 100 000 150 000 80 000 70 000 16 900-15 170" 13 700**

13 700" 250 000 250 000 60 000" 60 000"*

27 900"*

27 900**

100000""

100 000'*

100000 100000 150000 150000 1 116770 1 318 500 (141 600)

(141 600)

(101 940)

(201 600)

$ 873 230 975 300

• ResIuc e i-eco'er,,fin/a;cing

"^ Pollu tion cfiona l fina u;cing

.See Notes to Fm)*ancial StatoeJw;*s 1999 1998 32

CONSOLIDATED STATEMENTS OF CAPITALIZATION Derember 3 1 1000 100f3 LONG-TERM DEBT-CONTINUED First Mortgage Bonds - NSP-Wisconsin Series due:

Oct. 1, 2003, 5Y%

March 1, 2023, 7X°/o Dec. 1, 2026, 7Y%

Total Guaranty Agreements - NSP-Minnesota Series due:

Feb. 1, 1999-2003, 5.41%

May 1, 1999-2003, 5.70%

Feb. 1, 2003, 7.40%

Total Less current maturities Net 0THI-ER LONG-TERM DEBT NSP-Minnesota Senior Notes due Aug. 1, 2009, 6;/%

City of Becker Pollution Control Revenue Bonds - Series due Dec. 1, 2005, 7.25%

Anoka County Resource Recovery Bond - Series due Dec. 1, 1999-2008, 6.70%-7.15%

Anoka County Resource Recovery Bond - Series due Dec. 1, 2000-2008, 3.95%-4.60%

City of La Crosse Resource Recovery Bond - Series due Nov. 1, 2021, 6%

Viking Gas Transmission Company Senior Notes - Series due:

Oct. 31, 2008, 6.65%

Nov. 30, 2011, 7.1 %

Sept. 30, 2012, 7.31%

Sept. 30, 2014, 8.04%

NRG Energy, Inc. Senior Notes - Series due:

Feb. 1, 2006, 7.625%

June 15, 2007, 7.5%

June 1, 2009, 7.5%

Nov. 1, 2013, 8%

NRG debt secured solely by project assets:

NRG Northeast Generating debt reclassified from short-term (see Note 2)

Crockett Corp. LLP debt due Dec. 31, 2014, 8.13%

NRG Energy Center, Inc. (Minneapolis Energy Center) Senior Secured Notes Series due June 15, 2013, 7.31%

Pacific Generation Company debt due 2000-2007, 4.7%-9.9%

Various NEO Corporation debt due Jan. 31, 2008, 9.35%

Pittsburgh Thermal LP Notes due 2002-2004, 10.61%-10.729%

San Francisco Thermal LP Notes due Nov. 5, 2004, 10.6%

COBEE debt due April 21, 2000, 0.0%

United Power & Land Notes due March 31, 2000, 7.62%

Black Mountain Gas Industrial Development Bonds due June 1, 2004, May 1, 2005, 6%

Various Eloigne Company Affordable Housing Project Notes due 1999-2027, 1.0%-9.9%

Employee Stock Ownership Plan Bank Loans due 1999-2005, Variable Rate Miscellaneous Total Less current maturities Net Unamortized discount on long-term debt - net TOTAL LONG-TERM DEBT TOTAL CAPITALI ZA 'IION 40000

$ 40000 110000 110000 65 000 65 000

$ 215000

$ 215000 4900**

5 100" 22 250" 22 750" 3 500" 3 500" 30650 31350 (700)

(700) 29 950 30650

$ 250000 9 0001, 19 615' 18 600' 18 845 4 290 11900 19667 125 000 250 000 300 000 240 000

$ 9 000"*

20 600' 18 600' 20 978 4 650 12 833 125 000 250 000 646 564 255 000 68881 71783 26216 28586 17390 17792 6 800 5 905 5 761 5208 6041 3000 3000 47116 46024 11606 18504 27665 9 122 2394029 662513 (50 591)

(25 300)

$2343438

$ 637213 (8254)

(7017)

$3 453 364

$1 851 146

$6316234

$4637732 SResource recoveryfinancing SP1oeueton controi/ tnancing See Aotes to Financial Statements

( I20,lqnC4lgt 4042/rc.

"-n 4

C,.

33

/*T*l I

I* r I I

NOTES TO FINANCIAL STATEMENTS 34 34 1 SiimmaTr nfSianificnnr AcciunringTolicies Business and System f/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 com missions, which are the same in all material aspects.

Principles of Consolidation I The following wholly owned sub sidiaries of NSP-Minnesota are included in the consolidated financial statements. In this report, we refer to these companies collectively as NSP.

"° NSP-Wisconsin

" NRG Energy, Inc.

• Viking Gas Transmission Co.

Energy Masters International, Inc.

, Eloigne Co.

"Seren Innovations, Inc.

o Ultra Power Technologies, Inc.

NSP uses the equity method of accounting for its investments in partnerships, joint ventures and certain projects, mainly at NRG and Eloigne. We record our portion of earnings from international investments after subtracting foreign income taxes. In the consoli dation 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 I 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 compen sate, we estimate and record unbilled revenues from the monthly meter-reading dates to the month's end. NSP-Minnesota's rates include monthly adjustments for:

" changes in the average cost of fuel, including electricity and natural gas that NSP purchases, from base levels approved in the most recent rate case; and

" recovery of conservation and energy management program costs and incentives in Minnesota, which is reviewed annually.

NSP-Wisconsin's rates include a cost-of-energy adjustment clause for purchased gas, but not for purchased electricity or electric fuel.

We can request recovery of those electric costs prospectively through the rate review process, which normally occurs every two years in Wisconsin, and an interim fuel cost hearing process.

Utiliýy Plant and Retirements I Utility plant is stated at original cost. The cost of utility plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense.

The cost of utility plant retired, plus net removal cost, is charged to accumulated depreciation and amortization. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses.

Allowance for Funds Used during Construction (AFQ ' 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 I 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 decommis sioning - 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 decommis sioning 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 I Nuclear fuel expense, which is recorded as the plant uses fuel, includes the cost of:

nuclear fuel used o future spent nuclear fuel disposal, based on fees established by the U.S. Department of Energy (DOE)

NSP's portion of the cost of decommissioning or shutting down the DOE's fuel enrichment facility Environmental Costs I 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 environmen tal 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 responsi ble 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 deprecia tion expense levels we can recover in rates include a provision for these estimated removal costs.

NOTES TO FINANCIAL STATEMENTS Income Taxes I Based on the liability method, NSP defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities.

We use the tax rates that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, we account for the reversal of some temporary differences as current income tax expense. We defer investment tax credits and spread their benefits over the estimated lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which we summarize in Note 9. We discuss our income tax policy for international operations in Note 7.

Foreign Currency Translation I NSP's foreign operations generally use the local currency as their functional currency in translating interna tional 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 busi nesses before interest and taxes. We do the same for foreign currency derivative arrangements that do not qualify for hedge accounting.

Derivative Financial Instruments I 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 com mitments 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 instru ments 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 state ments 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 con tracts 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 com mitments are fulfilled as a component of operating expenses. NSP and NRG do not speculate in electricity or natural gas futures.

A final derivative instrument used by NSP and NRG is the interest rate swap. The cost or benefit of the interest rate swap agreements is recorded as a component of interest expense. None of these deriva tive 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 infor mation 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 I 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 instru ments are primarily commercial paper and money market funds.

Regulatory Deferrals I 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 SIAS No. 7 1:

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

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

Stock-Based Employee Compensation I 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 differ ence 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 reduc tion in earnings for 1999, 1998 and 1997 would have been less than 1 cent per share per year.

Development Costs i 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 becom ing operational, NRG expenses the capitalized costs in the year of the termination.

"a

-t a

35

NOTES TO FINANCIAL STATEMENTS Intangible Assets I 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 consis tent with the economic useful life of the assets. Our intangible assets are currently amortized over a range of 15 to 40 years. We periodi cally 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 I 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 S*hrr-Term Bnrrnvwrinu(

Short-term debt outstanding at Dec. 31 consiste Utility short-term debt Weighted average interest rate - Dec. 31 Nonregulated short-term debt Less amounts reclassified to long-term Net nonregulated short-term debt Weighted average interest rate - Dec. 31

"* series issued for pollution control and resource recovery financings

"* certain other series totaling $1 billion NSP-Minnesota and NSP-Wisconsin may apply property additions in lieu of cash on all series, as permitted by their first mortgage indenture.

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

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

d of:

' $153 million in 2000

• $190 million in 2001

$ $42 million in 2002

$ 420

$ 114

"* $290 million in 2003 5 $373 million in 2004

$1 026

$ 126 (647) 379 126 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 1 nng-Term DebL Except for minor exclusions, all property of NSP-Minnesota and NSP-Wisconsin is subject to the liens of the first mortgage indentures, which are contracts between the companies and their bond holders.

A lien on the related property secures other debt securities, as we indicate in the Consolidated Statements of Capitalization.

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

4 Connmnn Srick grid Incenrive 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 out standing 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 circum stances. If an employee retires, all options granted in 1999 will vest immediately and can be exercised over their 10-year life. The exercise price of an option is the market price of NSP stock on the date of grant. The plan previously granted other types of performance awards, some of which remain outstanding. Most of these perfor mance 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 pro grams, with the corresponding weighted average exercise price:

-t a C,;

n a

36

NOTES TO FINANCIAL STATEMENTS STOCK OPTION AND 'ERFORMANCE AWARDS 1000 i 005 cc -

L LnoiwnaS*no or saresj

'Ma 23 9

Outstanding Jan. 1 Options granted in January or February Options and awards exercised Options and awards forfeited Options and awards expired OUTSTANDING AT DEC. 31 IXERCISABI E AT DEC. 31 33 23 res AveragePrice 89

$23.57 93

$26.31

28)

$18.89 (8)

$26.45

10)

$25.64 36

$24.41 49

$24.06 The following table summarizes information about stock options outstanding at Dec. 31, 1999:

Pan"e oFExercse Prices

$I**3-2A1d7 021 ff-22 7i 3ý23 72-262RA Options Outstanding: (a)

Number outstanding at Dec. 31, 1999 Weighted average remaining contractual life (years)

Weighted average exercise price Options Exercisable: (a)

Number exercisable at Dec. 31, 1999 Weighted average exercise price

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 I NSP has two noncontributory, defined benefit 271 624 715 216 2 336 859 pension plans that cover almost all utility employees. Benefits are based on a combination of years of service, the employee's average 1.2 4.2 7.9 pay and Social Security benefits.

NSP's policy is to fully fund into an external trust the actuarially

$18.72

$21.96

$25.82 determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable 271624 715216 1 349786 employee benefit and tax laws. Plan assets principally consist of the common stock of public companies, corporate bonds and U.S.

$18.72

$21.96

$25.47 government securities.

(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 addi tional shares acquired through dividend reinvestment.

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

• 52,688 shares in 1997

• 49,651 shares in 1998

• 51,790 shares in 1999 Compensation expense related to these awards was immaterial.

Postretirement Health Care I 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 SEAS 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 bene fits 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.

Sha/res 2 206 572 (346)

(34)

(9) 2 389 1 847 Avergage Price

$22.57

$26.88

$22.39

$26.48

$23.24

$23.57

$23.34

,Shares 2 235 573 (520)

(60)

(22) 2 206 1 685 Average Price

$21.99

$23.72

$21.12

$23.60

$25.47

$22.57

$22.21 0g

-n

• 0 Ca 37 1997

NOTES TO FINANCIAL STATEMENTS RECONCILIATION OF FUNDED STATUS (Thousaznds of dollarf)

BENEFIT OBLIGATION AT JAN. 1 Service cost Interest cost Plan amendments Actuarial (gain) loss Benefit payments BENEFIT OBLIGATION AT DEC. 31 Fair value of plan assets at Jan. 1 Actual return on plan assets Employer contributions Benefit payments FAIR VALUE OF PLAN ASSETS AT DEC. 31 Funded status at Dec. 31 net asset (obligation)

Unrecognized transition (asset) obligation Unrecognized prior service cost Unrecognized net (gain) loss AMOUNT RECOGNIZED IN THE BALANCE SHEETS Prepaid benefit asset Accrued benefit liability WEIGHTED AVERAGE ASSUMPTIONS USED IN BENEFIT CALCULATIONS Discount rate at end of year Expected return on plan assets for year - before tax Rate of future compensation increase per year Rate of future health care cost increase per year:

Next succeeding year - age 65 and older Next succeeding year - under age 65 Final rate of increase in 2004 Effect of changes in the assumed health care cost trend rate for each year:

1% increase in APBO components at Dec. 31, 1999 1% decrease in APBO components at Dec. 31, 1999 1% increase in service and interest cost components of the net periodic cost 1% decrease in service and interest cost components of the net periodic cost COMPONENTS OF NET PERIODIC BENEFIT COST (Thnugands 4u ofLr*)r Service cost Interest cost Expected return on plan assets (1

Amortization of transition (asset) obligation Amortization of prior service cost Recognized actuarial (gain) or loss Net periodic benefit cost (credit) under SFAS 87 or 106 Credits not recognized due to effects of ratemaking NET PERIODIC BENEFIT COST (CREDIT) RECOGNIZED FOR FINANCIAL REPORTING 401(k) I 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.

1999 36421 86 429

[47 592)

(76) 21 210 (37 397)

(41 005) 36469 Pension Benefits 1999 1998

$1 143 464

$1 048 251 36421 31 643 86 429 78 839 184255 102315 (105 634)

(41 635)

(97 086)

(75 949)

Other Postretirement Benefits 1999 199R

$219762

$279230 196 3247 9 184 15896 (80 840)

(51 456) 8 269 (9 732)

(16 637)

(17 4231

$1 247 849

$1 143 464

$139934

$219762

$2221819

$1978538

$ 34514

$ 19783 293904 319230 3982 2471 13339 29683 (97 086)

(75 949)

(16 637)

(17 423)

$2418637

$2221 819

$ 35 198

$ 34514

$1 170788

$1 078355

$(104736)

$(185 248)

(311)

(387) 22073 104482 277350 114305 (2926)

(2399)

(1 381 889)

(1 167340) 10 580 3790 65938 24933

$ (75 009)

$ (79 375)

'5 T-o 38 6.5%

8.5%

4.5%

7.5%

8.0%

6.1%

8.1%

5.5%

6.5%

8.0%

6.1%

8.1%

5.0%

$12 188 (10 565) 749 (646)

Pension Benefits 1928

$ 31643 78 839 (129263)

(1 (76) 6 673 (27 727)

(39 911) 35 545 1997 27 680 72651

.15 359)

(76) 1 071 (20 762)

(34 795) 30 862 Other Postretirement Benefits 19_99 1998 1997 196

$3247

$ 5095 9 184 15896 18872 (2499)

(1 582)

(1 242) 2384 8335 10780 (288)

(175)

(5)

(4) 3 8 972 25 717 33 508 (4 536)

$ (4 366)

$ (3 933)

$ 8 972

$25 717

$33 508 ESOP i 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 com pensation expense, were $4.2 million in 1999, $4.3 million in 1998 and $4.4 million in 1997.

7.5%

8.5%

4.5%

NOTES TO FINANCIAL STATEMENTS 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.

62No-negulaatechEarnings Conatribution Income from nonregulated subsidiaries consists of the following:

rT

..J I..

r LLLL(LLf



Operating revenues Equity in operating earnings of unconsolidated affiliates Operating and development expenses, including project write-downs Interest and other income (loss), including gains from project sales Income from nonregulated businesses before interest and taxes Interest expense Income tax benefit NET INCOME FROM NONREGULATED SUBSIDIARIES Earnings per share from nonregulated subsidiaries Loss per share from write-down of investment in CellNet stock TOTAL NONREGULATED EARNINGS PER SHARE CONTRIBUTION 12999

$512 839 67 859 (500 803)

(456) 79439 (97 854) 52761

$ 34 346 1998

$182 230 79 884 (248 420) 37 477 51 171 (54 261) 41 791

$ 38701 1997

$223 571 18 600 (251 087) 2O 994 12078 (34 627) 38 032

$ 15483 0.22 0.26 0.11 (0.05) 0.17 0.26 0.11 7_Jnco-me-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:

Federal statutory rate Increases (decreases) in tax from:

State income taxes, net of federal income tax benefit Tax credits recognized Equity income from unconsolidated affiliates Regulatory differences - utility plant items Other - net EFFECTIVE INCOME TAX RATE

£Tho2~sazds~Eakrs)

Income taxes are comprised of the following expense (benefit) items:

Included in utility operating expenses:

Current federal tax expense Current state tax expense Deferred federal tax expense Deferred state tax expense Deferred investment tax credits Total Included in income taxes on nonregulared operations and nonoperating items:

Current federal tax expense Current state tax expense Current foreign tax expense Current federal tax credits Deferred federal tax expense Deferred state tax expense Deferred foreign tax expense Deferred investment tax credits Total TOTAL INCOME TAX EXPENSE 1999 I99,8 1997 35.0%

35.0%

35.0%

4.7%

4.7%

4.3%

(13.6)%

(8.9)%

(7.9)%

(4.2)%

(3.8)%

(2.5)%

2.3%

0.7%

1.1%

(1.4)%

(0.6)%

(1.0)%

22.8%

27.1%

29.0%

$111 280 29 113 (3 878)

(115)

(9 107) 127293 (15 740)

(3 949) 4 040 (30 137)

(4 066)

(4 097)

(6 868)

(194)

(61 011)

$ 66 282

$127 734 32 750 (6 625) 646 (9 122) 145 383 (15 732)

(6 744) 2358 (25 122) 11 132 1 566 (7736)

(310)

(40 588)

$104 795

$125 202 28812 (88)

(23)

(9 048) 144 855 (19 470)

(5 804) 236 (17 006)

(2 237)

(662)

(2 892)

(310)

(48 145)

$ 96710 39

NOTES TO FINANCIAL STATEMENTS NRG intends to indefinitely reinvest earnings from foreign opera tions except to the extent the earnings are subject to current U.S.

income taxes. Accordingly, U.S. income taxes and foreign with holding taxes have not been provided on a cumulative amount of unremitted earnings of foreign subsidiaries of approximately

$195 million and $158 million at Dec. 31, 1999 and 1998. The additional U.S. income tax and foreign withholding tax on the unremitted foreign earnings, if repatriated, would be offset in whole or in part by foreign tax credits. Thus, it is not practicable to estimate the amount of tax that might be payable.

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

(Tl~o,,,,',J(* RIdllr Deferred tax liabilities:

Differences between book and tax bases of property Regulatory assets Tax benefit transfer leases Other Total deferred tax liabilities Deferred tax assets:

Regulatory liabilities Deferred compensation, vacation and other accrued liabilities not currently deductible Deferred investment tax credits Other Total deferred tax assets NET DEFERRED TAX LIABILITY 908 320 $

886 099 70 546 103 640 23431 27170 20370 22961

$1 022667 $1039870 49412 $

75774 63 073 67 539 46969 51 003 47 000 29 565 206454 $

223881 816213 815 989

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

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

Distributions and redemption payments are guaranteed by NSP.

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

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

Remaining (Thousands ofadollars)

Amiortzation Period AFC recorded in plant (a)

Plant Lives Conservation programs (a) 3 Years Losses on reacquired debt Term of Related Debt Environmental costs Primarily 10 Years Unrecovered gas costs 1-2 Years State commission accounting adjustments (a)

Plant Lives Other "FOTAL RECULATORY ASSETS Deferred income tax adjustments Investment tax credit deferrals Unrealized gains from 1999

$112291 5 254 52 698 48 708 15 266 1998

$121 551 72 995 56242 50 158 16259 7641 7370 Various 6 269 7 365

$248 127 $331 940

$ 77433 $ 75066 78281 84865

-o

-o3

-u 40

\\ame Loy Yang Power A Enfield Energy Centre Gladstone Power Station COBEE (Bolivian Power Co. Ltd.)

MIBRAG mbH Cogeneration Corp. of America Schkopau Power Station Long Beach Generating El Segundo Generating Encina San Diego Combustion Turbines Energy Developments Limited Scudder Latin American Power Various independent power production facilities Various affordable housing limited partnerships Gearaophic A tea Australia Europe Australia South America Europe USA Europe USA USA USA USA Australia Latin America USA Econzomic interest 25.37%

25.00%

37.50%

49.10%

33.33%

20.00%

20.95%

50.00%

50.00%

50.00%

50.00%

29.14%

6.63%

450/6-50%

USA 200/6-99.9%

decommissioning investments 177 578 138 613 Pension costs - regulatory differences 84 198 53012 Conservation incentives 25 284 Fuel costs, refunds and other 18795 20683 TOTAl REGULATORY [ IABIIITIES

$461 569 $372 239 (a) Earns a return on investment in the ratemakingaprocess 10, Investments Accontied for by the Equiry Method NSP's nonregulated subsidiaries have investments in various inter national 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 pro jects' 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.

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NOTES TO FINANCIAL STATEMENTS Summarized Financial Information of Unconsolidated AffiliatesI 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 (Mil/ion, of dollar) 1999 1998 1997 Operating revenues

$1 752

$1 509

$1 698 Operating income

$ 215

$ 205 93 Net income

$ 200

$ 143 84 NSP's equity in earnings of unconsolidated affiliates 68 80 19 FINANCIAL POSITION (Million ofdollan) 1999

199, Current assets Other assets TOTAL ASSETS Current liabilities Other liabilities Equity

$ 748

$ 714 7461 8071

$8 209

$8 785

$ 716

$ 537 5246 5931 2247 2317 At Dec. 31, 1999, NRG had three interest rate swap agreements with notional amounts totaling approximately $393 million. The contracts are used to manage NRG's exposure to changes in interest rates. If the swaps had been discontinued on Dec. 31, 1999, NRG would have owed the counterparties approximately $3 million. Management believes that NRG's exposure to credit risk due to nonperformance by the counterparties to its hedging contracts is insignificant, based on the investment grade rating of the counterparties.

"* In September 1999, NRG entered into a $200 million swap agreement effectively converting the 7.5 percent fixed rate on its senior notes to a variable rate. It expires on June 1, 2009.

"* A second swap effectively converts a $16 million issue of variable rate debt into fixed rate debt. The swap expires on Sept. 30, 2002.

"* A third swap converts $177 million of floating rate debt into fixed rate debt. The swap expires on Dec. 17, 2014.

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

TOTAL LIABILITIES NSP's equity investmen in unconsolidated af F__inancia I nstrui Fair Values IThe estim financial instruments a (T h5ozsandl of dollars)

Cash, cash equivalents and short-term investments Long-term investments Long-term debt, including current portion AND EQUITY

$8 209

$8 785 NSP's Energy Marketing division uses energy futures contracts, along with physical supply, to hedge market risk in the energy ffiliates

$1 047

$ 863 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 ared Dec. 31 fair values of NSP's recorded Energy Marketing's hedge transactions is not significant.

ire as follows:

NRG's Power Marketing subsidiary uses energy forward contracts, 1999 1998 along with physical supply, to hedge market risk in the energy market. At Dec. 31, 1999, the notional amount of energy forward Carrying Fair Canying Fair contracts was approximately $207 million. If the contracts had Amount Value Amount Va/ue been terminated at Dec. 31, 1999, NRG would have received approximately $12 million based on price fluctuations to date.

55968 $

55 968 $

42 364 $

42 364 Management believes the risk ofcounterparty nonperformance with regards to any of NRG's hedging transactions is not significant.

$ 517129 $ 517129 $ 438981 $ 438981

$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 invest ments. 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 cur rent rates for debt of the same remaining maturities and credit quality.

Derivatives I 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).

Letters of Credit ý 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 out standing, 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-Joinr Plant Ownership NSP is part owner of an 860-megawatt coal-fired electric generat ing 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.

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• a 42S 1 3. Nuclear Obligarinn Fuel Disposal I NSP is responsible for temporarily storing used - or spent - nuclear fuel from its nuclear plants. The U.S. Department of Energy (DOE) is responsible for permanently storing spent fuel from NSP's nuclear plants as well as from other U.S. nuclear plants.

NSP has been funding its portion of the DOE's permanent disposal program since 1981. The fuel disposal fees are based on a charge of 0.1 cent per kilowatt-hour sold to customers from nuclear genera tion. 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 decom missioning 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 amor tized. Accordingly, we deferred the unamortized assessment of

$32 million at Dec. 31, 1999, as a regulatory asset.

Plant Decommissioning I Decommissioning of NSP's nuclear facilities is planned for the years 2010-2022, using the prompt dismantle ment 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 obliga tions no sooner than 2002. Using Dec. 31, 1999, estimates, NSP's adoption of the proposed accounting would result in the recording of the total discounted decommissioning obligation of $705 million as a liability, with the corresponding costs capitalized as plant and other assets and depreciated over the operating life of the plant. NSP has not yet determined the potential impact of the FASB's proposed changes in the accounting for site exit obligations, such as costs of removal, other than nuclear decommissioning. However, the ultimate decommissioning and site exit costs to be accrued are expected to be similar to the current methodology. The effects of regulation are expected to minimize or eliminate any impact on operating expenses and results of operations from this future accounting change.

Consistent with cost recovery in utility customer rates, NSP records annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Since the costs are expected to be paid in 2010-2022, funding presumes that cur rent 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 fund ing 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 oper ate 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 decommission ing 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 per cent 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 con sisted 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 cumu lative decommissioning accruals of $549 million. The following table summarizes the funded status of NSP's decommissioning obligation at Dec. 31, 1999:

NOTES TO FINANCIAL STATEMENTS (Thou*ands pfdollarf) 1999 Estimated decommissioning cost obligation from most recent approved study (1993 dollars)

$ 750 8 Effect of escalating costs to 1999 dollars (at 4.5% per year) 226 9 Estimated decommissioning cost obligation in current dollars 977 7 Effect of escalating costs to payment date (at 4.5% per year) 867 0 Estimated future decommissioning costs (undiscounted) 1 844 7 Effect of discounting obligation (using risk-free interest rate)

(1 140 0 Discounted decommissioning cost obligation 704 7 Assets held in external decommissioning trust 517 1 DISCOUNTED DECOMMISSIONING OBLIGATION IN EXCESS OF ASSETS CURRENTLY HELD IN EXTERNAL TRUST 1876 Decommissioning expenses recognized include the following components:

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lA 1999 199R 19 Seren expects to spend approximately $180 million during 2000, which reflects the build-out of its broadband communications net work 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 tempo rary nuclear fuel storage facility approval. These commitments can be met by building, purchasing, or in the case of biomass, converting generation resources.

53 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 con tracted by 2012, subject to least-cost determinations.

Annual decommissioning cost accrual reported as depreciation expense:

Externally funded Internally funded (including interest costs)

Interest cost on externally funded decommissioning obligation Earnings from external trust funds NET DECOMMISSIONING ACCRUALS RECORDED

$33 178

$33 178

$33 178 1595 1477 1 368 4 191 6960 7690 (4 191)

(6960)

(7690)

$34 773

$34 655

$34 546 Decommissioning and interest accruals are included with the accu mulated provision for depreciation on the balance sheet. Interest costs and trust earnings associated with externally funded obliga tions are reported in Other Utility Income and Deductions on the income statement.

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

14._Commitments and Cnng ingenr Iiabilitie Capital Commitments I 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 nonregulared 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 gener ation 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.

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 opera tional 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 improve ment 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 I NSP has sold a portion of its other receivables to a third party. The portion of the receivables sold consisted of cus tomer 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 bal ances. At Dec. 31, 1999, the outstanding balance of the loans was approximately $25 million. Based on prior collection experience of these loans, NSP believes that losses under the loan guarantees, if any, would have an immaterial impact on the results of operations.

Leases I 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.

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NOTES TO FINANCIAL STATEMENTS Fuel Contracts I 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 mini mum purchase of approximately $399 million of coal, $21 million of nuclear fuel and $235 million of natural gas and related trans portation, 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 Agreeinents ý NSP has several agreements to purchase elec tricity from the Manitoba Hydro-Electric Board (MH). A summary of the agreements is as follows:

POWER AGRLEME[NTS

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-n 44 Year; A[trnu1att 2000-2005 500 2000-2014 150 2000-2016 200 2000-2014 150 2000-2015 200 2015-2017 400 2018 200 The cost of the 500-megawatt participation power purchase commit ment 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 repre sent 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 miti gated 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 com mitments is approximately $45 million annually for 379 megawatts of summer capacity for 2000-2003. These commitments are expected to range between $52 million and $84 million annually for 2004-2024. These commitments are expected to decline to approx imately $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 combina tion 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 I 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 decontami nation 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 I 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 associ ated 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.

Participation power purchase Seasonal diversity exchanges:

Summer exchanges from MH Winter exchanges to MH

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

Eleven of these 14 sites have been remediated and, consistent with settlements reached with the EPA and other PRPs, NSP Minnesota has paid $2.4 million for its share of the remediation costs. One site that was previously remediated was reactivated due to a change in the use of the land. While these remedi ated sites will continue to be monitored, NSP-Minnesota expects that future remediation costs, if any, will be immate rial. Under applicable law, NSP-Minnesota, along with each PRP, could be held jointly and severally liable for the total remediation costs of PRP sites.

Neither the total remediation cost nor the final method of cost allocation among all PRPs of the three unremediated sites has been determined. However, NSP-Minnesota has recorded an estimate of approximately $0.1 million for its share of future costs for these sites. NSP-Minnesota is not aware of the other parties' inability to pay, nor does it know if responsibility for any of the sites is in dispute.

While it is not feasible to determine the ultimate impact of PRP site remediation at this time, the amounts accrued represent the best current estimate of NSP-Minnesotas future liability. It is NSP Minnesotas practice to vigorously pursue and, if necessary, litigate with insurers to recover incurred remediation costs whenever possi ble. Through litigation, NSP-Minnesota has recovered a portion of the remediation costs paid to date. Management believes remedia tion 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 investi gating. 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 for merly sites of gas manufacturing, gas storage plants or gas pipelines to determine if waste materials are present and if they are an environ mental or health risk. NSP-Minnesota also determines if it has any responsibility for remedial action and if recovery under NSP Minnesotas insurance policies can contribute to remediation costs.

"* NSP-Minnesota has remediated four sites, which continue to be monitored. NSP-Minnesota has paid $7.3 million to remediate these sites and expects to incur only immaterial monitoring costs related to these sites.

"* Another 11 gas sites remain under investigation. NSP Minnesota is taking remedial action at four of these sites.

"* As of Dec. 31, 1999, NSP-Minnesota had paid $4.3 million for the four active sites and had recorded an estimated liability of approximately $2.6 million for future costs at these sites, with payment expected over the next five years. This estimate is based on prior experience and includes investigation, reme diation and litigation costs.

No liability has been recorded for remediation or investigation of the remaining seven sites under investigation because the present land use at each of these sites does not warrant a response action.

While it is not feasible to determine at this time the ultimate cost of gas site remediation, the amounts accrued represent the best current estimate of NSP-Minnesota's future liability for any required cleanup or remedial actions at these former gas operating sites.

Environmental remediation costs may be recovered from insurance carriers, third parties or in future rates. The MPUC allowed NSP Minnesota to defer certain remediation costs of four active sites in 1994. In September 1998, the MPUC allowed the recovery of these gas site remediation costs in gas rates, with a portion assigned to NSP's electric operations for two sites formerly used by NSP gener ating 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 Superiors 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 VWDNR 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 esti mates 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.

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-C 46 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 cus tomers. 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 (NO5 ) emission regula tions affecting 22 states, including Wisconsin. The goal of the new regulations is to reduce NO5 emissions by 85 percent by May 1, 2003.

Two of NSP-Wisconsin's boilers and eight of its combustion tur bines may be affected by this action. If the existing boilers and combustion turbines are made compliant using retrofit technology to control NOx emissions, it could cost NSP-Wisconsin up to

$62 million for capital improvements and add $14 million each year for operation and maintenance expenses. This is the estimated cost of the most expensive alternative to achieve compliance, which is not necessarily the compliance alternative of choice. If the rules are finalized in their most stringent form, other alternatives for these older units may be deemed more cost effective than retrofitting.

How the WDNR will implement the new EPA NO. 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 EPAs final NOx rules. NSP-Wisconsin believes that the EPA improperly included Wisconsin in the scope of the regulatory action and it improperly calculated potential emissions of NO,, reducing the allowable emission limits for the state.

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

The Clean Air Act calls for phased-in reductions in emissions of sulfur dioxide and nitrogen oxides from electric generating plants. NSP has invested significantly over the years to reduce sulfur dioxide emissions at its plants. No additional capital expenditures are anticipated to comply with the sulfur dioxide emission limits of the Clean Air Act. NSP-Minnesota is completing installation of over-fire air at the King plant to meet the NO, 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 imple menting 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 commit ments 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 emis sion 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 cur rent 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 remedia tion and pollution control requirements, the potential effect of technological improvements, the number and financial strength of other potentially responsible parties at multi-party sites and the identification of new environmental cleanup sites. NSP has recorded and/or disclosed its best estimate of expected future environmental costs and obligations.

Legal Claims ý In the normal course of business, NSP is a party to routine claims and litigation arising from prior and current opera tions. 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 relat ing 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 dam ages 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 com panies 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 ulti mate cost to NSP, if any, is unknown at this time.

NOTES TO FINANC[AL STATEMENTS 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 tempo rary injunction hearing was held on Sept. 27, 1999. The acquisition of the Oswego generating station was closed on Oct. 22, 1999, following notification to the court of the closing date. NRG intends to continue to vigorously defend the suit and believes Fortistar's claims to be without merit. NRG has asserted numerous counterclaims against Fortistar.

15. ProposedBiisness 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 cur rently 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 combi nation and consistent with NSP's filed request for regulatory amortization over future periods.

Xcel Energy Summarized Pro Forma Information I 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 regu latory review and approval. However, the pro forma amounts for NSP and NCE include approximately $25 million and $20 million, respectively, of deferred nonrecurring merger costs as of Dec. 31, 1999, mainly those directly attributable to the merger transaction.

Assuming the business combination is accounted for as a pooling of interests, these costs will be expensed upon the consummation of the NCE/NSP merger. The pro forma income statement information amounts do not reflect any of these costs. The pro forma balance sheet information has been adjusted to reflect a write-off of the deferred costs and a related reduction of retained earnings.

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

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

As of Dec. 31, 1999:

XCEL ENERGY (Mi/lions ofcdoll/rd Plant - Net Current Assets Other Assets TOTAL ASSETS Common Equity Preferred Securities Long-Term Debt Total Capitalization Current Liabilities Other Liabilities TOTAL EQUITY AND LIABILITIES NJSP NCE Aumatnenti Pro Forma

$4451

$6261

$2087

$12799 1 034 1 027 2061 4283 1 034 (2 132) 3 185

$9768 $8322 (45) $18045

$2558 $2733 (45)

$ 5246 305 294 599 3454 2374 5828 6317 5401 (45) 11 673 1 826 1 657 3483 1 625 1264 2889

$9768 $8322 (45)

$18045 For the year ended Dec. 31, 1999:

XCEL ENERGY (Millions ofdollars, except mr e

.ho tnr noe Revenue Operating Income Net Income Available for Common EARNINGS PER SHARE -DILUTED NSP

$2 869 343 224

$ 219 MCE Adj

$3 375 642 347

$ 347 al'imenms Pro Forma

$625

$6 869 237 1 222 571

$ 566

$ 1.43 $ 3.01

$ 1.70 a

la a3 a7 foar earmn ig per s=42(

NOTES TO FINANCIAL STATEMENTS New NSP Utility Sub Summarized Pro Forma Information I 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.

As of Dec. 31, 1999:

NEW NSP UTILITY SUB (Mi//in,,,nfo//prI Utility Plant - Net Current Assets Other Assets TOTAL ASSETS Common Equity Preferred Securities Long-Term Debt Total Capitalization Current Liabilities Other Liabilities TOTAL EQUITY AND LIABILITIES ISP Adicuftmpntr Pro Forma

$4451

$ (856)

$3595 1 034 (434) 600 4283 (3416) 867

$9768

$(4 706)

$5062

$2 558

$(1 374)

$1 184 305 (305) 3 454 (2 077) 1 377 6317 (3756) 2561 1 826 (686) 1 140 1 625 (264) 1 361

$9768

$(4 706)

$5062 For the year ended Dec. 31, 1999:

NEW NSP UTILITY SUB (Millionm ofdoll/n*,

Revenue Operating Income Net Income AVAI LABLE FOR COMMON N.2 Adzuatienty Pro Forma

$2 869

$ (236)

$2 633 343 (64) 279 224 (74) 150

$ 219 (69)

$ 150 16 Segment and Related Information NSP has four reportable segments: Electric Utility, Gas Utility and two of its nonregulated energy businesses, its wholly owned subsidiaries NRG and EMI.

" NSP's Electric Utility generates, transmits and distributes electricity primarily in Minnesota, Wisconsin, Michigan, North Dakota and South Dakota. It also makes sales for resale and provides wholesale transmission service to various entities in the United States.

" NSP's Gas Utility transmits, transports, stores and distributes natural gas and propane primarily in Minnesota, Wisconsin, North Dakota, Michigan and Arizona.

"NRG develops, builds, acquires, owns and operates several nonregulated energy-related businesses, including indepen dent power production, commercial and industrial heating and cooling, and energy-related refuse-derived fuel produc tion, both domestically and outside the United States.

" EMI is an energy service company, primarily retrofitting and upgrading facilities for greater energy efficiency, in the United States.

In general, NSP has segmented its operations as either regulated or nonregulated businesses. Further, the regulated businesses are sepa rated between electric and gas; and nonregulated businesses are separated by company (primarily based on product and services).

The electric and gas businesses are part of NSP-Minnesota, NSP Wisconsin and Viking companies and are reviewed at various jurisdiction and/or company levels. They have been aggregated as reportable segments as they are aggregated for reporting to NSP's board of directors. Assets by segment are not reported to manage ment 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 compo nent, 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 man agement reporting and consolidated external NSP reporting.

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

"* directly assigned wherever applicable

" allocated based on cost causation allocators wherever applicable

" allocated based on a general allocator for all other costs not assigned by the above two methods The "all other" category includes segments that measure below the quantitative threshold for separate disclosure and consists primarily of nonregulated companies, including Eloigne, an affordable hous ing investment company; Seren, a broadband telecommunications company; Ultra Power, a power-cable testing company; and several other small companies and businesses.

48

NOTES TO FINANCIAL STATEMENTS BUSINESS SEGMENTS 1999 Operating revenues from external customers (b)

Intersegment revenues TOTAL REVENUES Depreciation and amortization Interest income Financing costs Income tax expense (credit)

Equity in earnings (losses) of unconsolidated affiliates Segment net income (loss) 1998 Operating revenues from external customers (b)

Intersegment revenues TOTAL REVENUES Depreciation and amortization Interest income Financing costs Income tax expense (credit)

Equity in earnings (losses) of unconsolidated affiliates Segment net income (loss) 1997 (Tlh,,,,,nn,1,d odllnn*)

Operating revenues from external customers (b)

Intersegment revenues TOTAL REVENUES Depreciation and amortization Interest income Financing costs Primergy cost write-off Income tax expense (credit)

Equity in earnings (losses) of unconsolidated affiliates Segment net income (loss)

Electric r T+.: i.,

$2 396 263 Gas

$471 780 ATJOC

$427 567 All Reconciling Consolidated EMI Other Eliminationy Total (a)

$ 48017

$ 37255

$3 380 882 833 4369 963

$ (5 197) 968

$2 397 096

$476 149

$428 530

$ 48 017

$ 37255

$ (5 197)

$3 381 850 322858 34857 37026 2223 6098 403062 2 189 658 10038 52 885 (165) 13657 121465 17055 92570 318 4966 (165) 236209 116601 8177 (26416)

(8061)

(24019) 66282 68 947 (1 088) 67 859

$ 178908

$19458

$ 57 195

$(19221)

$(12004)

$ 224336 Electric

$2 361 536 Gas T h÷;i,..

$456 710 ATD0/2

$ 98 688 L:'lAC All Reconciling Consolidated Other Eliminations Total (a)

$ 54254

$ 29288

$3 000 476 815 9292 1737

$(10916) 928

$2362351

$466002

$100425

$ 54254

$ 29288

$(10916) $3001404 308415 31 864 16320 2 129 3779 362507 9 103 1403 8052 184 776 (608) 18910 109 192 15485 50313 108 3997 (608) 178 487 135914 10672 (25654)

(4214)

(11 923) 104795 81706 300 (2122) 79884

$ 226351

$ 17321

$ 41732

$ (7659) 4628

$ 282373 Electric T r-, 1-1.

$2 217 542 Gas T T+ý.1:

$515 162 ATDf"*

$102 791 csA/rT All Reconciling Consolidated Other Fliminatios Total la)

$ 94375

$ 26405

$2 956 275 1 008 6113 926

$ (7005) 1042

$2218 550

$521 275

$103717

$ 94375

$ 26405

$ (7005) $2957317 299325 28609 10310 1 768 3069 343081 1 696 331 10 806 604 774 (482) 13729 111 595 13429 30729 272 3626 (482) 159 169 29 005 29 005 122655 12087 (23680)

(5921)

(8431) 96710 26003 (5 144)

(2259) 18600 199553

$ 22284

$ 21 982

$(10841)

$ 4342

$ 237320 (a) The Consolidated Total amounts for income and expense items represent the sum ofutility amounts (including some nonoperating items)firom 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. Howevei; NRG has significant equity investments for nonregulated projects outside of the United States. Equiiy in earnings of unconsolidated affiliates, primarily independent powerprojects, includes $38.6 million in 1999, $29.3 million in 1998 and $27.1 million in 1997from nonregulated projects located outside of the United States. NRCs equity invest ments in projects outside of the United States were $606 million in 1999, $557 million in 1998 and $517 million in 1997.

49

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NOTES TO FINANCIAL STATEMENTS

17. Summarized Quarterly Financial Data (Wnaudired)

(Thousands ofdollars, except per share amo*

Utility operating revenues Utility operating income Net income Earnings available for common stock Earnings per average common share:

Basic Diluted Dividends declared per common share Stock prices - high

- low (Thousands of dollars, exceppaer share amounts Utility operating revenues Utility operating income Net income Earnings available for common stock Earnings per average common share:

Basic Diluted Dividends declared per common share Stock prices - high

- low i;)

March 31 1999

$743 183 87 654 52 321 51 261

$0.34

$0.34

$0.3575

$27%6

$23X6 March 31. 1998

$701 402 79 050 57117 54 750

$0.37

$0.37

$0.3525

$292Y32

$260/

Quarter Ended rune 30. 1999 (a)

,.5es. 30. 1999

$627 157

$813482 47944 122566 11490 111 337 9380 110277

$0.06

$0.06

$0.3625

$263/A

$22*'/6

$0.72

$0.72

$0.3625

$24'06

$20'X Quarter Ended June30 1998 Sept 30. 1998(4)

$638 601

$766448 65054 134985 35 034 101 694 33 974 100 634

$0.23

$0.23

$0.3575

$30Y32

$27'Y32

$0.67

$0.67

$0.3575

$29Yi

$25 '/

Dec. 31. 1999 (a)

$685 189 85 315 49 188 48 126

$0.31

$0.31

$0.3625

$221X 6

$19Y6 Dec. 31-1998 (g)

$712 723 85 200 88 528 87 467

$0.58

$0.58

$0.3575

$302Y6

$26Y16 (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, 1999fourth quarter results include a pretax charge of $17 million, or 8 cents per share, to write offgoodwill related to EMI acquisitions.

Also, a pretax charge of$l1 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 fourth 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 ofNRG projects.

(c) 1998 results include a $26 million pretax gain, which increased fourth quarter earnings by 11 cents per share, for a partial sale ofan NRG project.

50 unr

REPORTS OF MANAGEMENT AND INDEPENDENT ACCOUNTANTS RLP F

PZL DE 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 prin ciples 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' fair ness 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 ensure 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 struc ture. 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.

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

PRICLEWATERHOUSECOOPERS LLP Minneapolis, Minnesota January 31, 2000, except as to Note 2, which is as of February 22, 2000 James J. Howard Chairman of the Board, President and Chief Executive Officer Edward J. McIntyre Vice President and Chief Financial Officer NORTHERN STATES POWER COMPANY Minneapolis, Minnesota January 31, 2000 51

OPERATING STATISTICS REGULATED 0 [LECIIRIC OPE0 RATIONS RF 1 \\ I 1,f I

K F S (Thotofand,/ nb-/la//ar) 52 1999

$ 809 528 405 620 489 633 504 195 31 668 (71 348) 1998

$ 774 803 389 744 466 352 483 595 31 054 6 673 1997

$ 739684 379 848 433 526 468 404 30 826 2 185 1996

$ 727 145 376 797 401 137 450 811 30 033 4 577 1995

$ 735 743 362 521 399 259 448226 29 162 (666)

Residential Small commercial and industrial Medium commercial and industrial Large commercial and industrial Streetlighting and other Conservation accrual adjustments (a)

Total retail Sales for resale Transmission and other ITOTA l, RL ETA I L SA L

E S (Million* ofkilowatt-hours)

Residential Small commercial and industrial Medium commercial and industrial Large commercial and industrial Streetlighting and other Total retail Sales for resale 101 AL CUSTOMER ACCOUNTS (at Dec. 31) (b)

Residential Small commercial and industrial Medium commercial and industrial Large commercial and industrial Streetlighting and other Total retail Sales for resale TOTAL AVERAGE P, I-\\FNUL PEP KILOWAT ITIOUR Residential Small commercial and industrial Medium commercial and industrial Large commercial and industrial TOTAL RLETA\\I 1

KI !.OWATT-HOUR OUT PUT (till/otas)

Thermal Hydro Purchased and interchange TOTA CAPABILITY AT TIMNE OF M AXItMU M DOEMA\\ND (megaivatts)

Company owned Purchased and sales - net (with reserve)

TOTAL Maximum demand (),egawatts)

Date of maximum demand (a) Represents excess (defjicieng,) of conseration incentives 'ecoganized as -evenaue bt contpa-isoit to tevels billed to,etail cmstoants znader *?tes i effect.

(b) Custotoe" acconts for 1996-2000 ina.' not befidly coatparabl/c to prioc.-,ears dit to difcfernces ini meter accautnlano, i t a aeltn bi//nigs)ysteni intplemented in 1996.

2169296 2152221 2054473 1990500 1974245 168581 149707 107464 98961 133961 59219 60423 56613 37952 34564

$2397096

$2362351

$2218550

$2127413

$2142770 10373 10127 9791 9847 9956 6117 5999 5907 6091 5763 8981 8801 8263 7470 7511 11 283 11277 11 059 11089 10941 325 327 335 336 329 37079 36531 35355 34833 34500 6724 6304 4658 4929 6500 43 803 42835 40 013 39762 41 000 1306900 1287080 1273 161 1252476 1 238576 160 880 155 536 150 103 149 134 144 774 9731 9510 9142 7962 7906 762 727 695 669 652 6365 6243 6276 5030 4883 1484638 1459096 1439377 1415271 1396791 82 78 59 54 67 1484720 1459 174 1439436 1415325 1396858 7.80t 7.65t 7.55t 7.38t 7.39¢ 6.63 6.50 6.43 6.19 6.29 5.45 5.30 5.25 5.37 5.32 4.47 4.29 4.24 4.07 4.10 5.85t 5.89q 5.81q 5.71t 5.72t 34091 32902 31 896 32657 33 802 845 696 1 015 1 194 1 049 12397 12529 10661 9065 9 189 47333 46127 43572 42916 44040 7176 7149 7117 7109 7100 2024 1 871 1706 1698 1 910 9200 9020 8823 8807 9010 7990 7660 7353 7487 7519 July 29 July 14 July 16 Aug. 6 July 13

OPERATING STATISTICS RI GULATIL U GAS OIPIRiPTIONS IT?.

JI ^ J.//I II....

7O00, 1000 Residential Commercial and industrial Firm Interruptible Other Total retail Interstate transmission (Viking)

Agency, transportation and off-system sales Elimination of Viking sales to NSP 1, 1AI L SA L ES (thousands of wnBtu)

Residential Commercial and industrial Firm Interruptible Other TOTAlI RETAI I.

0 T Il R G A S D I IL I \\' I. R E D (thousands of/nmiBtn)

Interstate transmission (Viking)

Agency, transportation and off-system sales Elimination of Viking sales to NSP TOTAl. OTIII I1 GAS D1II.ISRI D

CUSTOMER ACCOUNTS (atDec. 31) (a)

Residential Commercial and industrial Total retail Other gas delivered I-0 FA L AVLRAGE RIVEINUL PERL MNIBTU Residential Firm commercial and industrial Interruptible commercial and industrial TOIAL RL1AI L GAS PUR.CHASED FOR,ISAI. I!

10 UTILITY CUSTOMERS Total cost (tho/ands) (b)

Cost recognized per mmBtu sold (b)

Maximum sendout (/mnBtu)

Date of maximum sendout

$237 976 130 066 63 376 151 431 569 25 172 18 372 (3 198)

$226 936 124 099 61 050 114 412 199 23 375 23 792 (2 543)

$253 065 144 539 79 135 34 476 773 19 809 21 287 (2 673)

$267 130 146 145 63 585 153 477 013 17 553 34 662 (2435)

$215 543 119 863 48 646 1 686 385 738 16328 26 122 (2 374)

$471 915

$456 823

$515 196

$526 793

$425 814 40658 37522 42428 48 149 42294 26584 24410 28880 31748 28275 23732 23201 25898 23210 22408 97 48 33 394 772 91 071 85 181 97239 103501 93749 167360 168 187 166588 161 972 152952 13773 15609 11701 17535 19679 (15 114)

(14563)

(17145)

(19311)

(20440) 166 019 169 233 161 144 160 196 152 191 443692 430240 410773 398723 386007 50 886 44 523 41 905 40 244 38 575 494578 474763 452678 438967 424582 63 58 36 30 62 494641 474821 452714 438997 424644

$5.85

$6.05

$5.96

$5.55

$5.10 4.89 5.08 5.00 4.60 4.24 2.67 2.63 3.06 2.74 2.17

$4.74

$4.84

$4.90

$4.61

$4.11

$267859

$250661

$317646

$312943

$236714

$2.85

$2.78

$3.20

$3.00

$2.49 782702 710831 662025 737258 659800 Jan. 4 Jan. 10 Jan. 27 Feb. 1 Jan. 3 (a) Custowncr accountsfoi 1996-1999 ;nay not be fidly conparable to prior years due to difenr/ens in meter acci/nulation in a new billing systen inpleimuterd in 1996.

(b) Excludes cost and volunnr for other gas deti/jered.

'0

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NONREGULATED BUSINESS INFORMATION December 31 (Thanuands of do/larf) 1999 1998 EQUITY INVESTMtENT BY NONREGULATED BUSINISSES IN UNCONSOLIDATED PROJECTS (Including undistributed earnings and capitalized development costs)

Australian projects

$ 349893

$ 327841 European projects 138760 134 197 South American and Latin American projects 117 106 95 173 Affordable housing projects (U.S.)

53338 45411 U.S. power and energy projects 386951 259974 Other 1 200 Total equity investment in unconsolidated nonregulated projects

$1 047 248

$ 862 596 Nonregulated property of consolidated subsidiaries (net of accumulated depreciation) - primarily U.S. projects 2 086 476 282 524 Notes receivable from unconsolidated projects, including current portion 67 163 110 886 Current assets 375 275 107 541 Other assets 207306 126 110 TOTAL ASSETS OF NONREGULATED BUSINESSES

$3783468

$1489657 Long-term debt, including current maturities

$2 048 842

$ 578 233 Short-term debt (including intercompany) 379438 126236 Other current liabilities 159 679 39 183 Other liabilities 137150 69072 Total liabilities of nonregulated businesses 2725 109 812724 NSP's equity investment in nonregulated businesses 1 133 829 759 530 Cumulative currency translation adjustments (75 470)

(82 597)

Total equity of nonregulated businesses 1 058 359 676 933 TOTAL LIABILITIES AND EQUITY OF NONREGULATED BUSINESSES

$3783468

$1 489657

-1/4

-s

'a 1/4,,

1/4 1/4 C;

3 1/4

'a

-n 54 SIGNIFICANT NONREGULATED GENERATION PROJECTS OPERATING AT DEC. 31. 1999 Generation Proijert 2)oerarino_

Gladstone Power Station Loy Yang Power A Crockett Cogeneration Schkopau Power Station (a)

Cogeneration Corp. of America (b)

COBEE (Bolivian Power Co. Ltd.)

MIBRAG mbH Energy Developments Limited Scudder Latin American Power Projects (c)

Long Beach Generating El Segundo Generating Enfield Energy Centre Encina San Diego Combustion Turbines NRG Northeast Generatina LLC forationi Australia Australia USA Germany USA Bolivia Germany Australia Latin America USA USA UK USA USA USA 0!ewt for NRG NRG/CMS Generation NRG PreussenElektra Kraftwerke A.G.

Calpine COBEE MIBRAG Energy Developments Limited Stewart & Stevenson/Wartsila Southern California Edison Southern California Edison NRG/Indeck San Diego Gas & Electric NRG NRG Total 1 680 2000 240 960 575 219 233 274 772 530 1 020 396 965 253 6 980 NRG Ouzneuhip 37.50%

25.37%

57.67%

20.95%

20.00%

49.10%

33.33%

29.14%

6.63%

50.00%

50.00%

25.00%

50.00%

50.00%

100.00%

Mw 630 507 138 200 99 108 78 79 51 265 510 99 483 127 6 980 (a) Through a lease agreement, ANRG has ownership of200 megawatts.

(b) Cogeneration Coip. ofAmerica owns various percentages of'rojects, making NVRG; share ofownership 99 megawatts.

(c) Scudder owns various percentages ofprojects, making s\\RGs share of ownership 5I megawatts.

SHAREHOLDER INFORMATION Common stock shareholders at year-end Book value at year-end Market prices High Low Year-end closing Dividends declared per share 1999 1998 1997 1996 1995 81569 81 990 83232 86337 83902

$16.42

$16.25

$15.89

$15.47

$14.87

$27'%6

$30'`6

$29/6

$26'%6

$24Y

$19Y

$25'4/6

$22Y1/4

$221/4

$21X

$19'Y

$27%

$29%

$22'X6

$24Y6

$1.445

$1.425

$1.403

$1.373

$1.343

SHAREHOLDER INFORMATION Headquarters 1414 Nicollet Mall, Minneapolis, MN 55401 Internet Address I http://www.nspco.com Shareholders Information I Contact the NSP Shareholders Department at NSP headquarters toll-free at (800) 527-4677, or e-mail at shareholders@nspco.com; from the Minneapolis-St. Paul area, call (612) 330-5560.

Street-Name Shareholders and Beneficial Owners I To receive NSP's quarterly report, contact the Shareholders Department at the number listed previously.

Duplicate Mailings I If there are two or more shareholders at your address, you may have received duplicate shareholder mailings. To eliminate duplicate mailings, write or call the Shareholders Department at the number listed previously.

Direct Dividend Deposit I NSP offers direct deposit of dividends to shareholders' checking or savings accounts. To sign up for this free service, contact the Shareholders Department for information and an authorization form.

Dividend Reinvestment and Stock Purchase Plan I NSP's Dividend Reinvestment and Stock Purchase Plan offered by Prospectus is a convenient way to purchase shares of NSP's common stock without payment of any brokerage commission or service charge. Contact the Shareholders Department for a Prospectus and authorization form. Those eligible to participate in the plan are:

• Shareholders of record of NSP

• Shareholders who hold stock in "street name" through investment firms, provided the firm has established proce dures permitting participation

° Employees of NSP and its subsidiaries

• Non-shareholders of legal age who live in Minnesota, North Dakota, South Dakota, Wisconsin and Michigan. (Non shareholders must make an initial investment of at least $100.)

Once enrolled in the plan, participants may:

• Automatically reinvest all or a portion of their quarterly dividends

• Make additional cash investments. The minimum single pay ment is $25 and the maximum quarterly payment is $10,000.

Stock Exchange Listings and Ticker Symbol I Common stock is traded on the New York, Chicago and Pacific Exchanges. Ticker symbol: NSP. Newspaper stock tables list NSP as NoStPw, NoStPwr or NSPw. NYSE lists some of NSP's preferred stock and its preferred securities.

Form I 0-K (The Annual Report to the Securities and Exchange Commission) I Available online at: http://www.nspco.com/ir.htm or contact the Shareholders Department at the number listed previ ously. A statistical supplement to the annual report is also available.

Investor Relations I Internet address: http://www.nspco.com/ir.htm; Richard J. Kolkmann, Investor Relations, at NSP headquarters (612) 330-6622.

Schedule ofAnticipated Dividend Record Dates and Payment Dates for 2000:

Preferred Stock Common Stock Record Dates Paoment Dates Record Dates (a)

Payoent DLate (a)

Dec. 31, 1999 Jan. 15, 2000 Jan. 4, 2000 Jan. 20, 2000 March 31, 2000 April 15, 2000 April 13,2000 April 20,2000 June 30, 2000 July 15, 2000 July 13, 2000 July 20, 2000 Sept. 29, 2000 Oct. 15, 2000 Oct. 2, 2000 Oct. 20, 2000 Dec. 29, 2000 Jan. 15, 2001 (a) Dates for common dividends may change pending the Xcel Energy merger.

FISCAL AGENTS NSP-MINNESOTA Transfer Agent, Common and Preferred Stocks Northern States Power Company Registrar, Common and Preferred Stocks Norwest Bank Minnesota, N.A.

Sixth St. and Marquette Ave.

Minneapolis, MN 55479-0059 Dividend Distribution Northern States Power Company Forwarding Agent Norwest Bank International 3 New York Plaza, New York, NY 10004 Trustee-Bonds Harris Trust and Savings Bank (a)

S11 West Monroe St., Chicago, IL 60690 U.S. Bank Trust, N.A.

180 East 5th St., St. Paul, MN 55101 Norwest Bank Minnesota, N.A.,

Minneapolis Firstar Trust Company 1555 North River Center Drive, Suite 301 Milwaukee, WI 53212 Coupon PayingAgents-Bonds Harris Trust and Savings Bank, Chicago (a)

Firstar Trust Company, Milwaukee U.S. Bank Trust, N.A., St. Paul Norwest Bank Minnesota, N.A.,

Minneapolis Tender, Registrar and PayingAgent Chase Manhattan Bank 450 West 33rd St., New York, NY 10001 Trustee-Trust Orginated Preferred Securities (b)

Wilmington Trust Company 1100 North Market St.

Wilmington, DE 19807 (a) Harris Corporate Trust Services is being sold to Bank of New York in March 2000 (b) Securities of NSP Financing I, a wholly owned special purpose subsidiary trust of Northern States Power Company (Minnesota)

NSP-WI SCONS1 N Trustee-Bonds U.S. Bank Trust, N.A., St. Paul Firstar Trust Company, Milwaukee NRG FNFRGY. INC Trustee-Senior Notes Norwest Bank Minnesota, N.A.,

Minneapolis VIKING GAS Trustee-Bonds Norwest Bank Minnesota, N.A.,

Minneapolis

'55

DIRECTORS AND OFFICERS DIRECTORS OF THF MINNESOTA DavidA. Christensen (64) 2, 4 President and CEO Raven Industries, Inc.

(elected December 1976)

WJohn Driscoll (70) 2, 4 Retired Chairman and President Rock Island Company (elected November 1974)

Giannantonio Ferrari (60) 1, 3 Chief Operating Officer and Executive Vice President Honeywell International, Inc.

(elected October 1997)

JRINCIPAI OFFICERS OF THF Paul E. Anders Jr. (56)

Vice President and CIO Grady P Butts (53)

Vice President - Human Resources Jamesj. Howard (64)

Chairman, President and CEO Gary R. Johnson (53)

Vice President and General Counsel COM PANY Jamesj Howard (64) (a)

Chairman, President and CEO Northern States Power Company (elected January 1987)

Douglas W Leatherdale (63) 2, 3 Chairman and CEO The St. Paul Companies Inc.

(elected April 1991)

Dr. Margaret R. Preska (62) 2, 4 Distinguished Service Professor Minnesota State Universities (elected January 1980)

MINNESOTA COMPANY Cynthia L. Lesher (51)

President - NSP Gas Edwardj. McIntyre (49)

Vice President and CFO John P Moore Jr. (53)

Vice President and Corporate Secretary Paul E. Pender (45)

Vice President - Finance and Treasurer DIRECTORS OF THE WISCONSIN COMPANY Philip M. Gelatt (49) (b)

Ray A. Larson Jr. (70) (b)

President President Northern Engraving Corporation Wissota Sand and Gravel Company (elected May 1990)

(elected November 1979)

Jerome L. Larsen (51)

President and CEO NSP-Wisconsin (elected June 1998)

PRINCIPAl OFFICFRS OF THE WI Michael N. Gregerson (52)

Vice President - Marketing and Business Development Jerome L. Larsen (51)

President and CEO Larry G. Schnack (62) (b)

Chancellor University of Wisconsin Eau Claire (elected May 1988)

SCQNSIN COMPANY John P Moore Jr. (53)

Vice President and Corporate Secretary Roger D. Sandeen (54)

Vice President, Treasurer and Controller A. Patricia Sampson (51) 1, 4 President and CEO The Sampson Group, Inc.

(elected January 1985)

Allan L. Schuman (65) 1, 3 Chairman, President and CEO Ecolab Inc.

(elected January 1999)

Board Committees

1. Audit

2. Corporate Management

3. Finance

4. Power Supply (a) James J. Howard is an ex officio menmber ofall committees.

Roger D. Sandeen (54)

Vice President and Controller DavidM. Sparby (45)

Vice President Regulatory Services Loren L. Taylor (53)

President - NSP Electric Michael D. Wadley (43)

President - Nuclear Generation Loren L. Taylor (53)

President - NSP Electric (elected May 1992)

(b) Audit committee members Anthony G. Schuster (55)

Vice President Transmission Systems John D. Wilson (40)

Vice President - Regulatory Affairs and General Counsel C

C *2 56

f I1 41

BUL RAT U..

MINAPLS, MN