NORTHERN STATES POWER CO /MN/
8-K, EX-99.02, 2000-08-21
ELECTRIC & OTHER SERVICES COMBINED

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Exhibit 99.02—Supplemental Consolidated Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS

    Xcel Energy Inc., a Minnesota corporation, is a registered holding company under the Public Utility Holding Company Act of 1935. On August 18, 2000, NCE merged into NSP, with NSP as the surviving legal entity. NSP was renamed Xcel Energy Inc. Each share of NCE common stock was exchanged for 1.55 shares of Xcel Energy common stock. NSP shares became Xcel Energy shares on a one-for-one basis. Cash was paid to NCE shareholders in lieu of any fractional shares of Xcel Energy common stock upon exchange. Also in connection with the merger, all of NSP's pre-merger utility assets and liabilities were transferred to a new-formed utility subsidiary.

    The merger was structured as tax-free, stock-for-stock exchange for shareholders of both companies (except for fractional shares), and accounted for as a pooling of interests. The Supplemental Consolidated Financial Statements are presented as if the merger had been completed as of the beginning of the earliest period presented. The Supplemental Consolidated Financial Statements are not necessarily indicative of what the combined company's financial position or operating results would have been if the merger had been completed on the assumed completion dates.

    Xcel Energy owns the following direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries:

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NSP-Minnesota



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NSP-Wisconsin



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Public Service Company of Colorado



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Southwestern Public Service Company



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Black Mountain Gas



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Cheyenne Light, Fuel and Power Company



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Viking Gas Transmission Company



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WestGas InterState Inc.



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Xcel Wholesale Energy Group



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Xcel Energy Markets Group



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Xcel International Group



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Xcel Ventures



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Xcel Retail Services Group



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Xcel Communications Group



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New Century WYCO Inc.

    In addition, Xcel Energy, through the Xcel Wholesale Energy Group, owns 82 percent of the common stock of NRG Energy, Inc., a publicly traded independent power producer. Xcel Energy owned 100 percent of NRG until the second quarter 2000, when NRG completed its initial public offering. Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.

FINANCIAL REVIEW

    The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy's financial condition and results of operations during the periods presented, or

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are expected to have a material impact in the future. It should be read in conjunction with the accompanying Supplemental Consolidated 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:

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general economic conditions, including their impact on capital expenditures



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business conditions in the energy industry



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competitive factors



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unusual weather



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changes in federal or state legislation



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regulation



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the higher risk associated with Xcel Energy's nonregulated businesses as compared with its regulated business



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currency translation and transaction adjustments



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the items described under "Factors Affecting Results of Operations"



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the other risk factors listed from time to time by Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.04 to this Report on Form 8-K

RESULTS OF OPERATIONS

    Xcel Energy's earnings per share were $1.70, $1.91 and $1.24 for 1999, 1998 and 1997, respectively. Xcel Energy's 1997 earnings per share were $1.61 before an extraordinary item. The lower levels of earnings in 1999 and 1997 reflect the impact of several significant factors, as discussed below.

Significant Factors that Impacted 1999 Results

Conservation Incentive Recovery

    In June 1999, the MPUC denied NSP-Minnesota recovery of 1998 lost margins, load management discounts and incentives associated with state-mandated programs for electric energy conservation. Xcel Energy recorded a $35 million charge based on this action, which reduced 1999 earnings by 7 cents per share.

    At the end of 1999, the MPUC had not approved a conservation plan for 1999. Based on the change in MPUC policy on conservation incentives and regulatory uncertainty, management decided not to accrue any conservation incentives for 1999 or subsequent years.

EMI Goodwill

    In December 1999, Xcel Energy recorded a pretax charge (reported in special charges) of approximately $17 million, or about 4 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.

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Loss on Marketable Securities

    During 1999, Xcel Energy recorded pretax charges (reported in special charges) of approximately $14 million, or 3 cents per share, for a valuation write-down on its investment in the publicly traded common stock of CellNet Data Systems, Inc. In October 1999, CellNet announced it was experiencing financial difficulties and was contemplating restructuring its capital financing. In February 2000, CellNet filed for Chapter 11 bankruptcy protection.

Significant Factors that Impacted 1997 Results

U.K. Windfall Tax

    In July 1997, the U.K. government enacted a windfall tax on certain privatized business entities, payable in two installments with the first in December 1997 and the second in December 1998. The windfall tax was a retroactive adjustment to the privatization value based on post-privatization profits during the 1992 to 1995 period. During the third quarter of 1997, Xcel Energy's affiliate Yorkshire Power recorded an extraordinary charge of approximately $221 million (135 million pounds sterling) for this windfall tax. Xcel Energy's share of this tax was approximately $110.6 million, or 37 cents per share.

Merger Costs

    In May 1997, NSP and Wisconsin Energy Corp. mutually terminated their plans to merge. Earnings for 1997 were reduced by a pretax charge (reported in special charges) of $29 million, or 6 cents per share, to write off cumulative merger-related costs incurred. In August 1997, PSCo and SPS completed their merger and recorded a pretax charge (reported in special charges) of approximately $34 million, or 10 cents per share, for merger-related costs.

Electric Utility Margins

    The following table details the change in electric revenue and margin. Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel clause cost recovery mechanisms for retail customers in several states and the ability to vary wholesale prices with changing market conditions, most fluctuations in energy costs do not affect electric margin. However, the fuel clause cost recovery in the various jurisdictions does not allow for complete recovery of all variable production expenses, and, therefore, higher costs in periods of extreme temperatures can result in an adverse earnings impact.

    Electric revenue decreased by approximately $61 million, or 1.2 percent, in 1999, largely due to the disallowance of 1998 conservation incentives in Minnesota, which reduced revenues $78 million, as compared with 1998. In addition, wholesale revenue decreased due to lower non-firm sales. Despite customer growth, retail sales increased only 0.5 percent, largely due to mild weather in Colorado and Texas. Electric margin decreased by approximately $47 million, or 1.6 percent, in 1999, largely due to the disallowance of 1998 conservation incentives in Minnesota, which reduced margin by $78 million, as compared with 1998. The disallowance of 1998 conservation incentives was recorded during 1999, as a result of the timing of an MPUC decision. In addition, electric margin was reduced by approximately $19 million in 1999, due to higher purchased power costs in Minnesota and Wisconsin not recoverable in rates.

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    Electric revenue increased $316 million, or 6.8 percent, in 1998, largely due to retail sales growth of 3.2 percent and wholesale energy sales growth of 37.8 percent. Electric revenue also increased in 1998 due to revenue recognition of approximately $17 million for SPS's settlement of a 1985 FERC rate case. Electric margin increased by $121 million, or 4.2 percent, in 1998, due to electric sales growth and the SPS FERC settlement.

Gas Utility Margins

    The following table details the change in gas revenue and margin. The cost of gas tends to vary with changing sales requirements and unit cost of gas purchases. However, due to purchased gas cost recovery mechanisms for retail customers, fluctuations in the cost of gas have little effect on gas margin.

    Gas revenue increased by approximately $31 million, or 2.8 percent, and margin increased by approximately $7 million, or 1.6 percent, in 1999, largely due to increased retail sales, which increased 3.2 percent compared with 1998. In addition, gas revenue and margin in 1999 increased due to higher base rates resulting from PSCo's 1998 rate case, which became effective in July 1999.

    Gas revenue decreased by approximately $43 million, or 3.7 percent, in 1998, largely due to warm winter weather in Minnesota and Wisconsin, which reduced sales levels. Retail gas sales for Xcel Energy decreased 8.6 percent in 1998 compared with 1997. This decline in retail sales in 1998 was partially offset by increased transportation volume, which increased 7.6 percent compared with 1997. Gas margin increased by approximately $5 million, or 1.1 percent, in 1998, largely due to an increase in PSCo's base revenues associated with a rate increase effective in February 1997.

Nonregulated Operating Margins

    The following table details the change in nonregulated revenue and margin.

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Earnings from equity investments in 1997 is before an extraordinary item, relating to the U.K. windfall tax.

    Nonregulated and other revenue increased by approximately $307 million, or 79.9 percent, in 1999, largely due to NRG's acquisition of generation facilities during 1999 in the Northeast region of the United States. Earnings from equity investments decreased by approximately $4 million, or 3.4 percent, in 1999, primarily due to lower earnings from NRG's West Coast power generating affiliate as a result of cool summer weather during 1999 compared with the summer of 1998. Nonregulated margin increased by approximately $184 million, or 62.2 percent, in 1999, largely due to NRG's acquisition of generation facilities during 1999 in the Northeast region of the United States.

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    Nonregulated and other revenue decreased by approximately $36 million, or 8.6 percent, in 1998, primarily due to the exit of Energy Masters from the gas marketing business, which offset increased revenue from new projects at NRG. The margins on Energy Masters' gas marketing business were not material. Earnings from equity investments increased by approximately $63 million, or 118.9 percent, in 1998, largely due to increased equity earnings from new NRG projects, including El Segundo, Long Beach and certain Pacific Generation operations. Nonregulated margin increased by approximately $98 million, or 49.5 percent, in 1998, largely due to new projects at NRG.

Non-Fuel Operating Expense and Other Item

    Other utility operation and maintenance expense decreased approximately $34 million, or 2.6 percent, in 1999 primarily, due to lower benefit costs and cost control efforts. Regulated Other Operation and Maintenance Expense increased approximately $59 million, or 4.6 percent, in 1998, primarily due to timing of plant outages in Minnesota, Year 2000 remediation costs, nuclear regulatory costs, storm damage due to several severe wind storms in Minnesota and higher labor costs from wage rate increases.

    Nonregulated other operation and maintenance expense increased by approximately $79 million, or 35.3 percent, in 1999, and approximately $57 million, or 34.5 percent, in 1998. These increases are primarily due to costs of operations acquired, increased business development activities and legal, technical and accounting expenses resulting from NRG's expanding operations. In addition, costs also increased due to the acquisition of Planergy in April 1998, higher costs incurred in providing energy management and consulting services and Seren's expansion of its broadband communications in Minnesota.

    Depreciation and Amortization Expense increased $52 million, or 8.4 percent, in 1999 and increased $45 million, or 7.7 percent, in 1998, primarily due to acquisitions of generating facilities by NRG and increased additions to utility plant.

    During 1998, NRG recorded gains of approximately $26 million on the partial sale of NRG's interest in the Enfield project and approximately $2 million on the sale of NRG's interest in the Mid-Continent Power facility. NRG also recorded gains of approximately $9 million on the sale of various projects in 1997.

    Interest expense increased $70 million, or 20.2 percent, in 1999 and $13 million, or 3.9 percent, in 1998, primarily due to increased debt levels to finance several asset acquisitions by NRG.

Factors Affecting Results of Operations

    Xcel Energy'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, Xcel Energy's nonregulated businesses are becoming a more significant factor in Xcel Energy's earnings. The historical and future trends of Xcel Energy's operating results have been and are expected to be affected by the following factors:

Competition and Industry Restructuring

    The landscape of the electric and gas utility industry continues to change rapidly. The majority of states are moving forward to develop and implement retail competition with an unbundling of regulated energy services. Merger and acquisition activity over the past few years has been significant as utilities reach to expand their customer base and/or establish a strategic niche in preparing for the future. Certain traditional regulated utilities are divesting generation assets to further evolve this competitive environment, recover stranded costs and pursue other business opportunities. The transition to this

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competitive environment will be extremely challenging during the next few years and will most likely have significant impacts on the industry.

    In 1999, FERC Order 2000 was issued to advance the formation of regional transmission organizations on a voluntary basis. The FERC's goal is to provide a framework that allows the individual states flexibility to manage deregulation and to build upon the foundation it established in 1996, promoting the development of competitive bulk power markets through non-discriminatory open access of transmission services and the recovery of stranded costs.

    Some states have begun to allow retail customers to choose their electricity supplier, and many other states are considering retail access proposals. Electric restructuring legislation was passed in Texas and New Mexico during 1999. Overall, in these states, retail competition and customer choice are expected to be available to most customers by Jan. 1, 2002. In early January 2000, SPS filed its business separation plan in Texas for the unbundling of business activities into power generation, transmission and distribution and retail electric provider services. SPS is diligently working to satisfy the legislative and regulatory requirements of Texas and New Mexico in developing its transition plans. Major issues include market power, divestiture of generation capacity, transmission constraints, legal separation, refinancing of securities, implementing procedures to govern affiliate transactions, investments in information technology and the pricing of unbundled services, all of which have significant financial implications. Xcel Energy can not predict the outcome of its restructuring proceedings at this time. As these issues are addressed in 2000 and sufficient details are available to reasonably determine how this transition will affect the portions of the businesses whose pricing is being deregulated, SPS may discontinue applying regulatory accounting for those businesses. The resolution of these matters may have a significant impact on the financial position, results of operations and cash flows of Xcel Energy. For more information on restructuring in Texas and New Mexico, see Note 2 to Exhibit 99.03.

    With respect to other Xcel Energy regulatory jurisdictions, the Minnesota Legislature continues to study industry restructuring issues, but has determined that further study is necessary before any action can be taken. During 1998, an electric restructuring bill was passed in Colorado which establish an advisory panel to conduct an evaluation of restructuring. During 1999, this panel concluded that Colorado should not open its markets to outside competition. The 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 in these Midwestern states and their impact on Xcel Energy cannot be predicted at this time and may be significant.

Regulation

    The electric and gas rates charged to customers of Xcel Energy's utility subsidiaries, are approved by the FERC and the state regulatory commissions in which they operate. The rates are generally designed to recover plant investment, operating costs and an allowed return on investment. Xcel Energy requests changes in rates for utility services through filings with the governing commissions. Because comprehensive rate changes are requested infrequently in some states, changes in operating costs can affect Xcel Energy's financial results. 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.

    Except for Wisconsin electric operations, most of the retail rate schedules for Xcel Energy's utility subsidiaries provide for periodic 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 and Colorado, conservation and energy management program costs. In Minnesota, changes in electric

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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. PSCo has an incentive cost adjustment (ICA), which allows for a 50 percent / 50 percent sharing among customers and shareholders of certain fuel and energy cost increases and decreases.

    Regulated public utilities are allowed to record as assets certain costs that would be expensed by nonregulated enterprises and to record as liabilities certain gains that would be recognized as income by nonregulated enterprises. If restructuring or other changes in the regulatory environment occur, Xcel Energy may no longer be eligible to apply this accounting treatment and may be required to eliminate such regulatory assets and liabilities from its balance sheet. Such changes could have a material adverse effect on Xcel Energy's results of operations in the period the write-off is recorded. At Dec. 31, 1999, Xcel Energy reported on its balance sheet regulatory assets of approximately $382 million and regulatory liabilities of approximately $128 million that would need to be recognized in the income statement in the absence of regulation. In addition to a potential write-off of regulatory assets and liabilities, restructuring and competition may require recognition of certain "stranded costs" not recoverable under market pricing. Xcel Energy currently does not expect to write off any "stranded costs" unless market price levels change, or cost levels increase above market price levels. See Notes 1 and 15 to the Financial Statements for further discussion of regulatory deferrals.

Environmental Matters

    Xcel Energy incurs several types of environmental costs, including nuclear plant decommissioning, storage and ultimate disposal of spent nuclear fuel, disposal of hazardous materials and wastes, remediation of contaminated sites and monitoring of discharges into the environment. Because of greater environmental awareness and increasingly stringent regulation, Xcel Energy has experienced increasing environmental costs. This trend has caused, and may continue to cause, slightly higher operating expenses and capital expenditures for environmental compliance. In addition, NRG's recent acquisition of existing 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 Xcel Energy's operating expenses for environmental monitoring and disposal of hazardous materials and wastes were approximately:

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$55 million in 1999



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$56 million in 1998



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$56 million in 1997

    Xcel Energy's utility operations expect to spend approximately $60 million—65 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:

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$126 million in 1999



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$101 million in 1998



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$64 million in 1997

    Xcel Energy expects to incur approximately $42 million in capital expenditures for compliance with environmental regulations in 2000 and approximately $165 million for 2000-2004. In addition, NRG

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expects to incur approximately $44 million in capital expenditures for environmental compliance for 2000-2004. See Notes 6 and 14 to the Supplemental Consolidated Financial Statements for further discussion of Xcel Energy's environmental contingencies.

Weather

    Xcel Energy's earnings can be significantly affected by weather. Very hot summers and very cold winters increase electric and gas sales, but can also increase expenses, which may not be fully recoverable. Unseasonably mild weather reduces electric and gas sales.

Impact of Nonregulated Investments

    Xcel Energy's earnings from nonregulated operations has increased significantly due to acquisitions. Xcel Energy expects to continue investing in nonregulated projects, including domestic and international power production projects through NRG, international projects through the Yorkshire Power Group and broadband communications systems through Xcel Communications. Xcel Energy's nonregulated businesses may carry a higher level of risk than its traditional utility businesses due to a number of factors, including:

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



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



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development risks, including uncertainties prior to final legal closing.

    Some of Xcel Energy's nonregulated subsidiaries have project investments (as listed in Note 11 to the Supplemental Consolidated Financial Statements) consisting of minority interests, which may limit the financial risk, but also limit the ability to control the development or operation of the projects. In addition, significant expenses may be incurred for projects pursued by Xcel Energy's subsidiaries that do not materialize. The aggregate effect of these factors creates the potential for volatility in the nonregulated component of Xcel Energy's earnings. Accordingly, the historical operating results of Xcel Energy's nonregulated businesses may not necessarily be indicative of future operating results.

Accounting Changes

    The 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 Xcel Energy's balance sheet would occur upon implementation of the FASB's proposal, which would be no earlier than 2002. However, the effects of regulation are expected to minimize or eliminate any impact on operating expenses and earnings from this future accounting change. For further discussion of the expected impact of this change, see Note 6 to the Supplemental Consolidated Financial Statements.

    In June 1998, the FASB issued SFAS No. 133—Accounting for Derivative Instruments and Hedging Activities. This statement requires that all derivatives be recognized at fair value in the balance sheet and all changes in fair value be recognized currently in earnings or deferred as a component of other comprehensive income, depending on the intended use of the derivative, its resulting designation and its effectiveness. Xcel Energy plans to adopt this standard in 2001, as required. Xcel Energy has not yet determined the potential impact of implementing this statement.

Inflation

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

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Derivatives, Risk Management and Market Risk

    Xcel Energy uses derivative financial instruments to mitigate the impact of changes in foreign currency exchange rates on international project cash flows, natural gas, electricity and fuel prices on margins and interest rates on the cost of borrowing. Xcel Energy and its subsidiaries are exposed to market risks in both the energy trading and non-trading operations. Xcel Energy manages these market risks through various policies and procedures that allow for the use of various instruments in the energy and financial markets. See Notes 1 and 13 to the Supplemental Consolidated Financial Statements for further discussion of Xcel Energy's financial instruments and derivatives.

Commodity Price Risk

    Xcel Energy has a wholesale power marketing operation within its regulated subsidiaries. The primary objective of the regulated power marketing operation is to meet the requirements of Xcel Energy's retail and wholesale customers for low-cost power, while optimizing margins from generation resources. Xcel Energy's exposure to changes in commodity prices may increase, which may result in earnings volatility. To manage exposure to price volatility in the natural gas and electricity markets, a variety of energy contracts, both financial and commodity based, are utilized as hedges. These contracts consist mainly of commodity futures and options, index or fixed price swaps and basis swaps and are used by both the trading and non-trading operations. As of Dec. 31, 1999, a 10 percent increase or decrease in electricity futures and forward prices would have an immaterial impact on Xcel Energy's financial results. Any changes in the values of these futures contracts would be offset by a change in the underlying commodities being hedged. Due to cost-based rate regulation, Xcel Energy's regulated subsidiaries have limited exposure to commodity price.

    Xcel Energy also has a power marketing operation at NRG. 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 of 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.

Interest Rate Risk

    Xcel Energy and its subsidiaries have both long-term and short-term debt instruments that subject Xcel Energy and certain of its subsidiaries to the risk of loss associated with movements in market interest rates. This risk is limited for Xcel Energy's regulated companies primarily due to cost-based rate regulation. In the future, management anticipates utilizing financial instruments to manage its exposure to changes in interest rates. These instruments may include interest rate swaps, caps, collars and exchange-traded futures contracts and put or call options on U.S. Treasury securities.

    At Dec. 31, 1999, a 100 basis point change in the benchmark rate on Xcel Energy's variable debt would impact net income by approximately $12 million.

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

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Currency Exchange Risk

    Xcel Energy's investment in Yorkshire Power, a foreign currency denominated joint venture and various NRG projects, also expose Xcel Energy to currency translation rate risk. NRG has an investment in the Kladno project in the Czech Republic. 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.

    At Dec. 31, 1999, Xcel Energy's exposure to changes in foreign currency exchange rates through its investment in Yorkshire Power is not material to its consolidated financial position, results of operations or cash flows. Xcel Energy does not presently utilize financial instruments to manage its exposures to foreign currency exchange rate movements.

Credit Risk

    In addition to the risks discussed above, Xcel Energy and its subsidiaries are exposed to credit risk in risk management activities. Credit risk relates to the risk of loss resulting from the nonperformance of a counterparty of its contractual obligations. As Xcel Energy continues to expand its gas and power marketing and trading activities, its exposure to credit risk and counterparty default may increase. Xcel Energy and its subsidiaries maintain credit policies intended to minimize overall credit risk.

    Xcel Energy and its subsidiaries conduct standard credit reviews for all of its counterparties. Xcel Energy employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees and standardized master netting agreements that allow for offsetting of positive and negative exposures. The credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

    Cash provided by operating activities decreased slightly during 1999, compared with 1998, primarily due to a decrease in working capital due to timing of cash flows. Cash provided by operations increased in 1998, compared with 1997, primarily due to increased net income, higher depreciation and higher working capital in 1998.

    Cash used in investing activities increased during 1999, compared with 1998, primarily due to acquisitions of existing generating facilities by NRG and increased levels of utility capital expenditures.

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Cash used in investing activities decreased during 1998, compared with 1997, primarily due to the investment in Yorkshire Power and asset acquisitions by NRG in 1997.

    Cash provided by financing activities increased during 1999, compared with 1998, primarily due to the issuance of debt to finance NRG asset acquisitions in 1999. Cash provided by financing activities decreased during 1998, compared with 1997, primarily due to the issuance of long-term debt in 1997, primarily to fund the investment in Yorkshire Power and NRG's asset acquisitions. In addition, during 1998 the repayment of long-term debt and the redemption of preferred stock resulted in a use of cash by financing activities.

Prospective Capital Requirements

    The estimated cost as of Dec. 31, 1999, of the capital expenditure programs of Xcel Energy and its subsidiaries and other capital requirements for the years 2000, 2001 and 2002 are shown in the table below (in millions):

    The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates, due to changes in the electric system projected load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy's long-term energy needs. In addition, Xcel Energy's ongoing evaluation of merger, acquisition and divestiture opportunities to support corporate strategies, to address restructuring requirements and to comply with future requirements to install emission control equipment may impact actual capital requirements. For more information, see Note 12 on Regulatory Matters and Note 14 on Commitments and Contingencies to the Supplemental Consolidated Financial Statements.

    Xcel Energy and its subsidiaries continue to evaluate opportunities to enhance shareholder returns and achieve long-term financial objectives through investments in projects or acquisitions of existing businesses. Xcel Energy's subsidiaries expect to invest significant amounts in nonregulated projects in the future. Financing requirements for nonregulated project investments will vary depending on the success, timing and level of involvement in projects currently under consideration. These investments could cause significant changes to the capital requirement estimates for nonregulated projects and property. Long-term financing may be required for such investments.

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    NRG expects to invest approximately $2.7 billion in 2000 for nonregulated projects and property, which include acquisitions and project investments. NRG's future capital requirements may vary significantly. For 2000, NRG's capital requirements reflect expected acquisitions of existing generation facilities, including Cajun, Killingholme A and the Conectiv fossil assets.

    Seren, a subsidiary of Xcel Communications, expects to spend approximately $180 million during 2000, which reflects the build-out of its broadband communications network in northern California. Seren's capital requirements for 2001-2002 may vary significantly depending on the success of development efforts under way.

    Xcel Energy 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 to 2022.

Common Stock Dividend

    It is anticipated that Xcel Energy will initially adopt a dividend of $1.50 per share on an annual basis. The actual dividend level is dependent upon Xcel Energy's results of operations, financial position, cash flows and other factors, and will be evaluated by the Board of Directors of Xcel Energy.

Capital Sources

    Xcel Energy expects to meet future financing requirements by periodically issuing long-term debt, short-term debt, common stock and preferred securities to maintain desired capitalization ratios. Over the long term, Xcel Energy's equity investments in and acquisitions of nonregulated projects are expected to be financed at the nonregulated subsidiary level from internally generated funds or the issuance of subsidiary debt. Financing requirements for the nonregulated projects, in excess of equity contributions from partners, are expected to be fulfilled through project or subsidiary debt. Decommissioning expenses not funded by an external trust will be financed through a combination of internally generated funds, long-term debt and common stock. In addition, Seren is evaluating various financing options, including equity financing to third parties and project-secured debt. The financing needs are subject to continuing review and can change depending on market and business conditions and changes, if any, in the construction programs and other capital requirements of the Xcel Energy and its subsidiaries.

Registration Statements

    Effective at the time of the merger, Xcel Energy's Articles of Incorporation were amended to increase the authorized shares of common stock from 350 million to 1 billion. As of Dec. 31, 1999, Xcel Energy had approximately 335 million shares of common stock outstanding. In addition, Xcel Energy's Articles of Incorporation authorize the issuance of 7 million shares of $100 par value preferred stock. As of Dec. 31, 1999, Xcel Energy has 1,050,000 shares of preferred stock outstanding.

    PSCo has an effective shelf registration statement under which $300 million of senior debt securities are available for issuance.

    During the second half of 2000, NSP-Minnesota plans to file a $400 million universal debt shelf registration.

    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.

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    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 filing 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 to the Supplemental Consolidated Financial Statements).

Short-Term Borrowing Arrangements

    Xcel Energy plans to secure various credit lines and borrowing arrangements subsequent to its creation in 2000. Until then, subsidiary credit facilities will provide financing to meet Xcel Energy's short-term capital requirements.

    At the end of 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.

    PSCo and its subsidiaries have available committed lines of credit to meet their short-term cash requirements. PSCo and its subsidiaries have a credit facility with several banks which provides $300 million in committed bank lines of credit and is used primarily to support the issuance of commercial paper by PSCo and PSCCC, and to provide for direct borrowings thereunder. The facility expires Nov. 17, 2000. Additionally, PSCo has a credit facility, which provides $300 million in committed lines of credit and expires on June 23, 2000. As of Dec. 31, 1999, PSCo had used $355.6 million of the total capacity available under its committed lines of credit. Generally, the banks participating in the credit facility would have no obligation to continue their commitments if there has been a material adverse change in the consolidated financial condition, operations, business or otherwise that would prevent PSCo and its subsidiaries from performing their obligations under these credit facilities. Individual PSCo arrangements for uncommitted bank lines of credit totaled $150 million at Dec. 31, 1999, none of which were used or outstanding.

    PSCCC may periodically issue medium-term notes to supplement the financing or purchase of PSCo's customer accounts receivable and fossil fuel inventories. As of Dec. 31, 1999, PSCCC had issued and had outstanding $100 million in medium-term notes. The level of financing of PSCCC is tied directly to daily changes in the level of PSCo's outstanding customer accounts receivable and monthly changes in fossil fuel inventories and will vary minimally from year to year although seasonal fluctuations in the level of assets will cause corresponding fluctuations in the level of associated financing.

    SPS has two credit facilities, which provide $250 million in committed bank lines of credit, each with a commitment termination date of Feb. 22, 2000. As of Dec. 31, 1999, SPS had used $181 million of the total capacity available under its committed lines of credit.

    At the end of 1999, banks provided $550 million of credit lines to NRG. At Dec. 31, 1999, NRG had borrowed $340 million against these lines.

13

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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

TO XCEL ENERGY INC.:

    We have audited the consolidated balance sheets of New Century Energies, Inc. (a Delaware corporation) and subsidiaries as of December 31, 1999 and 1998, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1999 (not presented herein). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

    We conducted our audits in accordance with generally accepted auditing standards. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

    In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of New Century Energies, Inc. and its subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with generally accepted accounting principles.

    We have also made a similar audit of the accompanying supplemental consolidated balance sheets and statements of capitalization of Xcel Energy Inc. and subsidiaries at December 31, 1999 and 1998, and the related supplemental consolidated statements of income, stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 1999. The supplemental consolidated financial statements give retroactive effect to the merger between New Century Energies, Inc. and Northern States Power Company on August 18, 2000, which has been accounted for as a pooling of interests as described in Note 1. These supplemental financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these supplemental financial statements based on our audit.

    We did not audit the financial statements of Northern States Power Company included in the supplemental consolidated financial statements on Xcel Energy Inc., which statements reflect total assets and revenues constituting 54% percent and 50% percent, respectively, in 1999 and 49% percent and 47% percent, respectively, in 1998 and total revenues constituting 47% percent in 1997 of the related supplemental consolidated totals. These statements were audited by other auditors whose report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for Northern States Power Company, is based solely upon the report of the other auditors.

    We conducted our audit in accordance with generally accepted auditing standards. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit and the report of other auditors provide a reasonable basis for our opinion.

14

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    In our opinion, based upon our audit and the report of the other auditors, the supplemental consolidated financial statements referred to above present fairly, in all material respects, the financial position of Xcel Energy Inc. and its subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 1999, after giving retroactive effect to the merger between New Century Energies, Inc. and Northern States Power Company as described in Note 1, all in conformity with accounting principles generally accepted in the United States.

/s/ ARTHUR ANDERSEN LLP   
ARTHUR ANDERSEN LLP

Denver, Colorado,
August 18, 2000.

15

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Report of Independent Accountants

To the Shareholders of

Northern States Power Company:

    In our opinion, the consolidated balance sheets and statements of capitalization as of December 31, 1999 and 1998 and the related consolidated statements of income, of common stockholders' equity and of cash flows for each of the three years in the period ended December 31, 1999 of Northern States Power Company and its subsidiaries (not presented separately herein) present fairly, in all material respects, the financial position, results of operations and cash flows of Northern States Power Company and its subsidiaries at December 31, 1999 and 1998 and for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.

PRICEWATERHOUSECOOPERS LLP

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

16

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XCEL ENERGY INC. AND SUBSIDIARIES

SUPPLEMENTAL CONSOLIDATED STATEMENTS OF INCOME

(Thousands of Dollars, Except per Share Data)

				Year ended December 31
				1999			1998			1997
Operating revenues:
	Electric utility			$	4,924,363		$	4,985,319		$	4,669,048
	Gas utility				1,141,429			1,110,004			1,152,535
	Nonregulated and other				691,488			383,852			420,348
	Equity earnings from investments in affiliates				112,124			115,985			52,766
		Total revenue			6,869,404			6,595,160			6,294,697
Operating expenses:
	Electric fuel and purchased power—utility				1,958,912			1,973,043			1,777,592
	Cost of gas sold and transported—utility				683,455			659,493			706,685
	Cost of sales—nonregulated and other				323,262			204,331			275,412
	Other operating and maintenance expenses—utility				1,307,136			1,341,468			1,282,919
	Other operating and maintenance expenses—nonregulated				302,201			223,374			166,117
	Depreciation and amortization				679,851			627,438			582,408
	Taxes (other than income taxes)				360,916			356,045			358,530
	Special charges				31,114			790			63,093
		Total operating expenses			5,646,847			5,385,982			5,212,756
Operating income					1,222,557			1,209,178			1,081,941
Other income (deductions)—net					(18,874	)		8,878			4,592
Gains on the sale of nonregulated projects					—			29,951			8,702
Interest charges and financing costs:
	Interest charges—net of amounts capitalized				414,277			344,643			331,760
	Distributions on redeemable preferred securities of subsidiary trusts				38,800			33,311			22,287
	Dividend requirements and redemption premium on preferred stock of subsidiaries				—			5,332			11,752
		Total interest and financing costs			453,077			383,286			365,799
Income before income taxes and extraordinary item					750,606			864,721			729,436
Income taxes					179,673			240,391			230,629
Income before extraordinary item					570,933			624,330			498,807
Extraordinary item—U.K. windfall tax					—			—			(110,565	)
Net income					570,933			624,330			388,242
Dividend requirements and redemption premiums on Xcel Energy preferred stock					5,292			5,548			11,071
Earnings available for common shareholders				$	565,641		$	618,782		$	377,171
Weighted average common shares outstanding:
	Basic				331,943			323,883			303,042
	Diluted				332,054			324,355			303,422
Earnings per share—basic and diluted:
	Income before extraordinary item			$	1.70		$	1.91		$	1.61
	Extraordinary item				—			—			(0.37	)
	Net income			$	1.70		$	1.91		$	1.24

See Notes to Supplemental Consolidated Financial Statements

17

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XCEL ENERGY INC. AND SUBSIDIARIES

SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

					Year ended December 31
					1999			1998			1997
Operating activities:
	Net income				$	570,933		$	624,330		$	388,242
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization				718,323			659,226			612,191
		Nuclear fuel amortization				50,056			43,816			40,015
		Deferred income taxes				18,277			5,231			46,309
		Amortization of investment tax credits				(14,916	)		(14,654	)		(15,562	)
		Allowance for equity funds used during construction				(1,130	)		(8,509	)		(6,400	)
		Undistributed equity in earnings of unconsolidated affiliates				(67,926	)		(56,952	)		(36,532	)
		Extraordinary item—U.K. windfall tax				—			—			110,565
		Write-down of investments in projects				31,346			26,740			16,052
		Write-off of Primergy merger costs				—			—			25,289
		Gain on sale of projects				(37,194	)		(26,200	)		1,994
		Conservation incentive adjustments—noncash				71,348			—			—
		Change in accounts receivable				(113,521	)		8,373			(7,366	)
		Change in inventories				(44,183	)		(12,550	)		(10,881	)
		Change in other current assets				(164,995	)		22,263			(60,437	)
		Change in accounts payable				214,791			2,105			(5,223	)
		Change in other current liabilities				81,056			60,618			(36,267	)
		Change in other assets and liabilities				13,164			27,767			(27,765	)
			Net cash provided by operating activities			1,325,429			1,361,604			1,034,224
Investing activities:
	Nonregulated capital expenditures and asset acquisitions					(1,620,462	)		(58,748	)		(195,527	)
	Utility capital/construction expenditures					(1,178,663	)		(1,014,710	)		(869,540	)
	Allowance for equity funds used during construction					1,130			8,509			6,400
	Proceeds from disposition of property, plant and equipment					83,190			9,369			2,117
	Investments in external decommissioning fund					(39,183	)		(41,360	)		(41,261	)
	Equity investments, loans and deposits for nonregulated projects					(240,282	)		(234,214	)		(765,507	)
	Collection of loans made to nonregulated projects					81,440			109,530			87,128
	Other investments—net					(40,054	)		642			(28,738	)
		Net cash used in investing activities				(2,952,884	)		(1,220,982	)		(1,804,928	)
Financing activities:
	Short-term borrowings—net					1,315,027			(84,471	)		181,759
	Proceeds from issuance of long-term debt					1,215,312			641,123			719,598
	Repayment of long—term debt, including reacquisition premiums					(465,045	)		(394,506	)		(369,258	)
	Proceeds from issuance of preferred securities					—			187,700			193,315
	Proceeds from issuance of common stock					95,317			234,171			554,834
	Redemption of preferred stock, including reacquisition premiums					—			(276,824	)		(41,943	)
	Dividends paid					(492,456	)		(476,172	)		(441,346	)
		Net cash provided by (used in) financing activities				1,668,155			(168,979	)		796,959
	Net increase (decrease) in cash and cash equivalents					40,700			(28,357	)		26,255
	Cash and cash equivalents at beginning of year					99,031			127,388			101,133
	Cash and cash equivalents at end of year				$	139,731		$	99,031		$	127,388
Supplemental disclosure of cash flow information
	Cash paid for interest (net of amount capitalized)				$	458,897		$	397,680		$	374,569
	Cash paid for income taxes (net of refunds received)				$	193,448		$	209,781		$	212,947

See Notes to Supplemental Consolidated Financial Statements

18

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XCEL ENERGY INC. AND SUBSIDIARIES

SUPPLEMENTAL CONSOLIDATED BALANCE SHEETS

Thousands of Dollars

				Year ended December 31
				1999			1998
ASSETS
Current assets:
	Cash and cash equivalents			$	139,731		$	99,031
	Accounts receivable—net of allowance for bad debts of $13,043 and $10,018, respectively				800,066			673,360
	Accrued unbilled revenues				410,798			269,553
	Materials and supplies inventories at average cost				306,524			179,565
	Fuel and gas inventories at average cost				152,874			136,083
	Prepayments and other				250,951			199,030
		Total current assets			2,060,944			1,556,622
Property, plant and equipment, at cost:
	Electric utility plant				14,807,684			14,176,818
	Gas utility plant				2,266,516			2,084,250
	Nonregulated property and other				3,242,410			1,304,977
	Construction work in progress				533,046			521,732
		Total property, plant and equipment			20,849,656			18,087,777
	Less: accumulated depreciation				(8,153,434	)		(7,629,745	)
	Nuclear fuel—net of accumulated amortization of $923,336 and $873,281, respectively				102,727			101,749
		Net property, plant and equipment			12,798,949			10,559,781
Other assets:
	Investments in unconsolidated affiliates				1,439,002			1,203,470
	Nuclear decommissioning fund investments				514,011			436,936
	Other investments				137,075			107,028
	Regulatory assets				566,727			700,101
	Other				553,650			490,852
		Total deferred charges and other assets			3,210,465			2,938,387
		Total Assets		$	18,070,358		$	15,054,790
LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt			$	431,049		$	507,365
	Short-term debt				1,432,686			764,224
	Accounts payable				793,139			556,879
	Taxes accrued				260,676			255,658
	Dividends payable				127,568			124,921
	Other				438,101			348,038
		Total current liabilities			3,483,219			2,557,085
Deferred credits and other liabilities:
	Deferred income taxes				1,779,046			1,762,230
	Deferred investment tax credits				214,008			229,369
	Regulatory liabilities				442,204			358,768
	Benefit obligations and other				420,140			381,718
		Total deferred credits and other liabilites			2,855,398			2,732,085
Minority interest in subsidiaries					14,696			13,516
Capitalization (see Statements of Capitalization):
	Long-term debt				5,827,485			4,056,691
	Mandatorily redeemable preferred securities of subsidiary trusts (see Note 5)				494,000			494,000
	Preferred stockholders' equity				105,340			105,340
	Common stockholders' equity				5,290,220			5,096,073
Commitments and contingencies (see Note 14)
		Total Liabilities and Equity		$	18,070,358		$	15,054,790

See Notes to the Supplemental Consolidated Financial Statements.

19

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XCEL ENERGY INC. AND SUBSIDIARIES

SUPPLEMENTAL CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY

(Thousands of Dollars)

				Par Value			Premium			Retained Earnings			Shares Held by ESOP			Accumulated Other Comprehensive Income			Total Stockholders' Equity
Balance at Dec. 31, 1996				$	747,121		$	1,461,106		$	2,113,990		$	(19,091	)	$	2,794		$	4,305,920
Net income											388,242									388,242
Currency translation adjustments																	(61,539	)		(61,539	)
Comprehensive income for 1997																				326,703
Dividends declared:
	Cumulative preferred stock of Xcel										(9,923	)								(9,923	)
	Common stock										(467,130	)								(467,130	)
Premium on redeemed preferred stock of Xcel											(1,148	)								(1,148	)
Issuances of common stock—net					55,124			510,108												565,232
Tax benefit from stock options exercised								1,009												1,009
Other											(106	)								(106	)
Repayment of ESOP loan(a)														8,558						8,558
Balance at Dec. 31, 1997				$	802,245		$	1,972,223		$	2,023,925		$	(10,533	)	$	(58,745	)	$	4,729,115
Net income											624,330									624,330
Unrealized loss from marketable securities, net of tax of $4,417																	(6,416	)		(6,416	)
Currency translation adjustments																	(16,089	)		(16,089	)
Comprehensive income for 1998																				601,825
Dividends declared:
	Cumulative preferred stock of Xcel										(5,548	)								(5,548	)
	Common stock										(475,399	)								(475,399	)
Issuances of common stock—net					23,150			223,985												247,135
Pooling of interests business combinations											6,065									6,065
Tax benefit from stock options exercised								850												850
Loan to ESOP to purchase shares(a)														(15,000	)					(15,000	)
Repayment of ESOP loan(a)														7,030						7,030
Balance at Dec. 31, 1998				$	825,395		$	2,197,058		$	2,173,373		$	(18,503	)	$	(81,250	)	$	5,096,073
Net income											570,933									570,933
Recognition of unrealized loss from marketable securities, net of tax of $4,417																	6,416			6,416
Currency translation adjustments																	(3,587	)		(3,587	)
Comprehensive income for 1999																				573,762
Dividends declared:
	Cumulative preferred stock of Xcel										(5,292	)								(5,292	)
	Common stock										(489,813	)								(489,813	)
Issuances of common stock—net					12,930			92,247												105,177
Pooling of interests business combination											4,599									4,599
Tax benefit from stock options exercised								58												58
Repurchase of common stock					(132	)		(1,109	)											(1,241	)
Repayment of ESOP loan(a)														6,897						6,897
Balance at Dec. 31, 1999				$	838,193		$	2,288,254		$	2,253,800		$	(11,606	)	$	(78,421	)	$	5,290,220

---

(a)

Did not affect cash flows

See Notes to Supplemental Consolidated Financial Statements

20

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XCEL ENERGY INC. AND SUBSIDIARIES

SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Thousands of Dollars)

				Dec. 31
				1999			1998
Long-Term Debt
NSP-Minnesota Debt
First Mortgage Bonds, Series due:
	Feb. 1, 1999, 51/2%			$	—		$	200,000
	Dec. 1, 1999 - 2006, 6.00% - 6.75%				—			16,900	(a)
	Dec. 1, 1999 - 2006, 3.50 - 4.10%				15,170	(a)		—
	Dec. 1, 2000, 53/4%				100,000			100,000
	Oct. 1, 2001, 77/8%				150,000			150,000
	March 1, 2003, 57/8%				100,000			100,000
	April 1, 2003, 63/8%				80,000			80,000
	Dec. 1, 2005, 61/8%				70,000			70,000
	April 1, 2007, 6.80%				60,000	(b)		60,000	(b)
	March 1, 2011, Variable Rate, 5.75% at 12/31/99 and 4.3% at 12/31/98				13,700	(b)		13,700	(b)
	March 1, 2019, Variable Rate, 3.7% at 12/31/99 and 3.1% at 12/31/98				27,900	(b)		27,900	(b)
	Sept. 1, 2019, Variable Rate				100,000	(b)		100,000	(b)
	July 1, 2025, 71/8%				250,000			250,000
	March 1, 2028, 61/2%				150,000			150,000
Guaranty Agreements, Series due: Feb. 1, 1999 - May 1, 2003, 5.41% - 7.40%					30,650	(b)		31,350	(b)
NSP-Minnesota Senior Notes Due Aug. 1, 2009, 67/8%					250,000			—
City of Becker Pollution Control Revenue Bonds—Series due Dec. 1, 2005, 7.25%					9,000	(b)		9,000	(b)
Anoka County Resource Recovery Bond—Series due Dec. 1, 1999 - 2008, 6.70% - 7.15%					—			20,600	(a)
Anoka County Resource Recovery Bond—Series due Dec. 1, 2000 - 2008, 3.95% - 4.60%					19,615	(a)		—
Other					1,458			135
Unamortized discount-net					(6,604	)		(5,280	)
		Total			1,420,889			1,374,305
Less redeemable bonds classified as current (See Note 3)					141,600			141,600
Less current maturities					104,673			203,700
		Total NSP-Minnesota long-term debt		$	1,174,616		$	1,029,005
PSCo Debt
First Mortgage Bonds, Series due:
	Jan. 1, 2001, 6.00%			$	102,667		$	102,667
	April 15, 2003, 6.00%				250,000			250,000
	March 1, 2004, 81/8%				100,000			100,000
	March 1, 2004, 57/8%, retired				—			21,500	(b)
	Nov. 1, 2005, 63/8%				134,500			134,500
	June 1, 2006, 71/8%				125,000			125,000
	April 1, 2008, 55/8%				18,000	(b)		18,000	(b)
	Nov. 1, 2009, 73/8%, retired				—			27,250	(b)
	June 1, 2012, 51/2%				50,000	(b)		50,000	(b)
	April 1, 2014, 57/8%				61,500	(b)		61,500	(b)
	Jan, 1, 2019, 5.1%				48,750	(b)		—
	July 1, 2020, 97/8%				70,000			75,000
	March 1, 2022, 83/4%				148,000			150,000
	Jan. 1, 2024, 71/4%				110,000			110,000
Unsecured Senior A Notes, due July 15, 2009, 6.78%					200,000			—
Secured Medium-Term Notes, due March 15, 1999 - March 5, 2007, 6.02% - 9.25%					256,500			296,500
Other secured long-term debt 13.25%, due in installments through Oct. 1, 2016					30,298			30,755
PSCCC Unsecured Medium-Term Notes due May 30, 2000, 5.86%					100,000			100,000
Unamortized discount					(6,998	)		(4,616	)
Capital lease obligations, 6.68% - 11.21% due in installments through May 31, 2025					56,565			39,555
		Total			1,854,782			1,687,611
Less current maturities					132,823			44,481
		Total PSCo long-term debt		$	1,721,959		$	1,643,130

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(a)

Resource recovery financing

(b)

Pollution control financing

See Notes to Supplemental Consolidated Financial Statements

21

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				Dec. 31
Long-Term Debt—continued (Thousands of Dollars)				1999			1998
SPS Debt
First Mortgage Bonds, Series due:
	Dec. 1, 1999, 67/8%, retired			$	—		$	90,000
	July 15, 2004, 71/4%				135,000			135,000
	March 1, 2006, 61/2%				60,000			60,000
	July 15, 2022, 81/4%				36,000			40,000
	Dec. 1, 2022, 8.20%				89,000			100,000
	Feb. 15, 2025, 8.50%				60,267			70,000
Unsecured Senior A Notes, due March 1, 2009, 6.2%					100,000			—
Pollution control obligations, securing pollution control revenue bonds,
	Not collateralized by First Mortgage Bonds due:
	July 1, 2011, 5.2% (converted to fixed rate June 1999 and variable rate of 4.3% at 12/31/98)				44,500			44,500
	July 1, 2016, Variable rate, 4.7% at 12/31/99 and 4.15% at 12/31/98				25,000			25,500
	Sept. 1, 2016, 53/4% series				57,300			57,300
	Less: funds held by Trustee:				(168	)		(168	)
Other					—			112
Unamortized discount and premium—net					(1,024	)		(1,013	)
		Total			605,875			620,731
Less current maturities					—			90,113
		Total SPS long-term debt		$	605,875		$	530,618
NRG Debt
NRG Energy, Inc. Senior Notes, Series due
	Feb. 1, 2006, 7.625%			$	125,000		$	125,000
	June 15, 2007, 7.5%				250,000			250,000
	June 1, 2009, 7.5%				300,000			—
	Nov. 1, 2013, 8%				240,000			—
NRG debt secured solely by project assets:
	NRG Northeast Generating debt reclassified from short-term (see Note 2)				646,564			—
	Crockett Corp. LLP debt due Dec. 31, 2014, 8.13%				255,000			—
	NRG Energy Center, Inc. Senior Secured Notes, Series due June 15, 2013, 7.31%				68,881			71,783
	Various debt due 2000 - 2008, 0.0% - 10.729%				62,072			50,269
Other					18,631			—
		Total			1,966,148			497,052
Less current maturities					30,524			9,329
		Total NRG long-term debt		$	1,935,624		$	487,723
NSP-Wisconsin Debt
First Mortgage Bonds Series due:
	Oct. 1, 2003, 53/4%			$	40,000		$	40,000
	March 1, 2023, 71/4%				110,000			110,000
	Dec. 1, 2026, 73/8%				65,000			65,000
City of La Crosse Resource Recovery Bond—Series due Nov. 1, 2021, 6%					18,600	(a)		18,600	(a)
Unamortized discounts					(1,650	)		(1,737	)
		Total NSP-Wisconsin long-term debt			231,950			231,863
Other Subsidiaries' Long-Term Debt
First Mortgage Bonds—Cheyenne:
	Series due April 1, 2003; - Jan 1, 2024, 7.50% - 77/8%				12,000			12,000
	Industrial Development Revenue Bonds due Sept. 1, 2021 - March 1, 2027, variable rate (5.60% and 4.05% at Dec. 31, 1999 and 1998)				17,000			17,000
Viking Gas Transmission Company Senior Notes—Series due Oct. 31, 2008 - Sept. 30, 2014, 6.65% - 8.04%					54,702			38,461
Various Eloigne Company Affordable Housing Project Notes due 1999 - 2027, 1.0% - 9.9%					47,116			46,024
Other					48,072			39,009
		Total			178,890			152,494
Less current maturities					21,429			18,142
		Total Other long-term debt		$	157,461		$	134,352
Total long-term debt				$	5,827,485		$	4,056,691

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(a)

Resource recovery financing

(b)

Pollution control financing

See Notes to Supplemental Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CAPITALIZATION (Continued)

(Thousands of Dollars)

				Dec. 31
(Thousands of dollars)				1999			1998
Mandatorily Redeemable Preferred Securities of Subsidiary Trusts each holding as its sole asset junior subordinated deferrable debentures of NSP-Minnesota, PSCo and SPS, respectively—(See Note 5)				$	494,000		$	494,000
Cumulative Preferred Stock—authorized 7,000,000 shares of $100 par value outstanding shares: 1999 and 1998, 1,050,000
		$3.60 series, 275,000 shares		$	27,500		$	27,500
		4.08 series, 150,000 shares			15,000			15,000
		4.10 series, 175,000 shares			17,500			17,500
		4.11 series, 200,000 shares			20,000			20,000
		4.16 series, 100,000 shares			10,000			10,000
		4.56 series, 150,000 shares			15,000			15,000
		Total			105,000			105,000
	Premium on preferred stock				340			340
		Total preferred stockholders' equity		$	105,340		$	105,340
Common Stockholders' Equity
	Common stock—authorized 350,000,000 shares of $2.50 par value issued shares: 1999, 335,277,321; 1998, 330,157,668			$	838,193		$	825,395
	Premium on common stock				2,288,254			2,197,058
	Retained earnings				2,253,800			2,173,373
	Leveraged common stock held by ESOP—shares at cost: 1999, 392,325; 1998, 641,884				(11,606	)		(18,503	)
	Accumulated other comprehensive income				(78,421	)		(81,250	)
		Total common stockholders' equity		$	5,290,220		$	5,096,073

See Notes to Supplemental Consolidated Financial Statements

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NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS

1.  Summary of Significant Accounting Policies

Merger and Supplemental Financial Statements (Basis of Presentation)

    On March 24, 1999, NCE and NSP entered into an Agreement and Plan of Merger, which provided for a strategic business combination involving NCE and NSP in a "merger-of-equals" transaction. On Aug. 18, 2000, following receipt of all required regulatory approvals, NSP and NCE merged and formed Xcel Energy Inc. Each share of NCE common stock was exchanged for 1.55 shares of Xcel Energy common stock. NSP shares became Xcel Energy shares on a one-for-one basis. Cash was paid in lieu of any fractional shares of Xcel Energy common stock. The merger was structured as tax-free, stock-for-stock exchange for shareholders of both companies (except for fractional shares) and accounted for as a pooling of interests. At the time of the merger, Xcel Energy registered as a holding company under the Public Utility Holding Company Act of 1935.

    Pursuant to the Merger Agreement, NCE was merged with and into NSP. NSP, as the surviving legal corporation, changed its name to Xcel Energy. Also, as part of the Merger, NSP transferred its existing utility operations that were being conducted directly by NSP at the parent company level to a newly formed wholly-owned subsidiary of Xcel Energy which was renamed NSP-Minnesota. Xcel Energy has the following public utility subsidiary companies:. NSP-Minnesota, NSP-Wisconsin, PSCo, SPS, Cheyenne and BMG.

    Operating revenues and earnings available for common shareholders were as follows (in thousands):

    Compared with amounts previously reported, NSP's operating revenues have been reclassified to include nonregulated operating revenues and equity earnings from unconsolidated affiliates. Similarly, NCE's operating revenues have been reclassified to include equity earnings from unconsolidated affiliates.

Business and System of Accounts

    Xcel Energy is a registered holding company under PUHCA and its domestic utility subsidiaries are engaged principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. Xcel Energy and its subsidiaries are subject to the regulatory provisions of the PUHCA. The utility subsidiaries are subject to regulation by the FERC and state utility commissions in Minnesota, Wisconsin, North Dakota, South Dakota, Michigan, Arizona, Colorado, Texas, New Mexico, Wyoming, Kansas and Oklahoma. All of the utility companies' accounting records conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material aspects.

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Principles of Consolidation

    Xcel Energy owns the following direct subsidiaries, which are included in the consolidated financial statements:

•

NSP-Minnesota



•

NSP-Wisconsin



•

Public Service Company of Colorado



•

Southwestern Public Service Company



•

Black Mountain Gas



•

Cheyenne Light, Fuel and Power Company



•

Viking Gas Transmission Company



•

WestGas InterState Inc.



•

Xcel Wholesale Energy Group



•

Xcel Energy Markets Group



•

Xcel International Group



•

Xcel Ventures



•

Xcel Retail Services Group



•

Xcel Communications Group



•

New Century WYCO Inc.

    Several of these subsidiaries are intermediate holding companies with additional subsidiaries, which are also consolidated. For example, the Xcel Wholesale Energy Group owns a controlling interest in the common stock of NRG Energy, Inc., a publicly traded independent power producer. Xcel Energy owned 100 percent of NRG until the second quarter 2000, when NRG completed its initial public offering. Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.

    Xcel Energy uses the equity method of accounting for its investments in partnerships, joint ventures and certain projects. We record our portion of earnings from international investments after subtracting foreign income taxes. In the consolidation process, we eliminate all significant intercompany transactions and balances.

Revenue Recognition

    Xcel Energy records utility revenues based on a calendar month, but reads meters and bills customers according to a cycle that doesn't necessarily correspond with the calendar month's end. To compensate, we estimate and record unbilled revenues from the monthly meter-reading dates to the month's end.

    Xcel Energy's utility subsidiaries have adjustment mechanisms in place, which currently provide for the recovery of certain purchased gas and electric energy costs. These cost adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically, as

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prescribed by the appropriate regulatory agencies, for any difference between the total amount collected under the clauses and the recoverable costs incurred.

    PSCo's rates in Colorado are adjusted under a performance-based regulatory plan, which takes into account changes in energy costs. SPS' rates in Texas and New Mexico have periodic fuel filing and reporting requirements, which can provide cost recovery. NSP-Wisconsin's rates include a cost-of-energy adjustment clause for purchased gas, but not for purchased electricity or electric fuel. In Wisconsin, we can request recovery of those electric costs prospectively through the rate review process, which normally occurs every two years, and an interim fuel cost hearing process. For more information, see Note 12—Regulatory Matters in the Supplemental Consolidated Financial Statements.

    In addition, NSP-Minnesota and PSCo's rates include monthly adjustments for the recovery of conservation and energy management program costs and incentives in Minnesota, which are reviewed annually.

Property, Plant, Equipment and Depreciation

    Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of 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.

    Xcel Energy determines the depreciation of its plant by spreading the original cost equally over the plant's useful life. Depreciation expense, expressed as a percentage of average depreciable property, ranged from approximately 3.2-3.4 percent for the years ended Dec. 31, 1999, 1998 and 1997.

Allowance for Funds Used During Construction

    AFDC, a noncash item, represents the cost of capital used to finance utility construction activity. AFDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFDC capitalized as a utility construction cost is credited to Other Income and Deductions—Net (for equity capital) and interest charges (for debt capital). AFDC amounts capitalized are included in Xcel Energy's rate base for establishing utility service rates. In addition to construction-related amounts, AFDC is also recorded to reflect returns on capital used to finance conservation programs in Minnesota. Interest capitalized as AFDC was approximately $19 million in 1999, $25 million in 1998 and $21 million in 1997.

Decommissioning

    Xcel Energy accounts for the future cost of decommissioning—or permanently retiring—its nuclear generating plants through annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning costs. Our decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends over the estimated lives of the plants. The calculation assumes that NSP-Minnesota and NSP-Wisconsin will recover those costs through rates. (See Note 6 to the Supplemental Consolidated Financial Statements for more information on nuclear decommissioning.)

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Nuclear Fuel Expense

    Nuclear fuel expense, which is recorded as the plant uses fuel, includes the cost of nuclear fuel used and future spent nuclear fuel disposal, based on fees established by the U.S. DOE and NSP's portion of the cost of decommissioning or shutting down the DOE's fuel enrichment facility.

Environmental Costs

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

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

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

Income Taxes

    Xcel Energy and its subsidiaries file consolidated Federal and consolidated and separate state income tax returns. Income taxes are allocated to the subsidiaries based on separate company computations of taxable income or loss. Investment tax credits have been deferred and are being amortized over the service lives of the related property. Deferred taxes are provided on temporary differences between the financial accounting and tax bases of assets and liabilities using the tax rates that are in effect at the balance sheet date.

    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 15 to the Supplemental Consolidated Financial Statements. We discuss our income tax policy for international operations in Note 8 to the Supplemental Consolidated Financial Statements.

Foreign Currency Translation

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

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

Derivative Financial Instruments

    Xcel Energy and its subsidiaries utilize a variety of derivatives, including interest rate swaps and locks, foreign currency hedges and energy contracts. The energy contracts are both financial and commodity based, in the energy trading and energy non-trading operations, to reduce their exposure to commodity price risk. These contracts consist mainly of commodity futures and options, index or fixed price swaps and basis swaps.

    Xcel Energy and its subsidiaries adopted EITF 98-10, "Accounting for Energy Trading and Risk Management Activities", effective Jan. 1, 1999. EITF 98-10 requires gains or losses resulting from market value changes on energy trading contracts to be recorded in earnings. The initial adoption of EITF 98-10 had an immaterial impact on Xcel Energy's net income.

    Energy contracts are also utilized by Xcel Energy and its subsidiaries in non-trading operations to reduce commodity price risk. Hedge accounting is applied only if the contract reduces the price risk of the underlying hedged item and is designated as a hedge at its inception. Gains and losses related to qualifying hedges of firm commitments or anticipated transactions are deferred and recognized as a component of purchased power or cost of gas sold when settlement occurs. If, subsequent to the inception of the hedge, the underlying transactions are no longer likely to occur, the related gains and losses are recognized currently in income.

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

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

    A final derivative instrument used by Xcel Energy is the interest rate swap. The cost or benefit of the interest rate swap agreements is recorded as a component of interest expense. None of these derivative financial instruments are reflected on Xcel Energy's balance sheet. For further discussion of Xcel Energy's risk management and derivative activities, see Note 13 to the Supplemental Consolidated Financial Statements.

Use of Estimates

    In recording transactions and balances resulting from business operations, Xcel Energy uses estimates based on the best information available. We use estimates for such items as plant depreciable lives, tax provisions, uncollectible amounts, environmental costs, unbilled revenues and actuarially determined benefit costs. We revise the recorded estimates when we get better information or when we

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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

    Xcel Energy considers investments in certain debt instruments—with a remaining maturity of three months or less at the time of purchase—to be cash equivalents. Those debt instruments are primarily commercial paper and money market funds.

Regulatory Accounting

    Xcel Energy's regulated utility subsidiaries account for certain income and expense items using SFAS No. 71—Accounting for the Effects of Regulation. Under SFAS No. 71:

•

we defer certain costs, which would otherwise be charged to expense, as regulatory assets based on our expected ability to recover them in future rates; and



•

we defer certain credits, which would otherwise be reflected as income, as regulatory liabilities based on our expectation they will be returned to customers in future rates.

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

Stock-Based Employee Compensation

    Xcel Energy has several stock-based compensation plans. We accounts for those plans using the intrinsic value method. We do not record compensation expense for stock options because there is no difference between the market price and the purchase price at grant date. We do, however, record compensation expense for restricted stock that Xcel Energy awards to certain employees, but holds until the restrictions lapse or the stock is forfeited. We do not use the optional accounting under SFAS No. 123—Accounting for Stock-Based Compensation. If we had used the SFAS No. 123 method of accounting, the reduction in earnings for 1999, 1998 and 1997 would have been approximately 1 cent per share per year. For more information, see Note 9 to the Supplemental Consolidated Financial Statements.

NRG Development Costs

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

Intangible Assets and Deferred Financing Costs

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

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of seven to 40 years. We periodically evaluate the recovery of goodwill based on an analysis of estimated undiscounted future cash flows. At Dec. 31, 1999, Xcel Energy's intangible assets included $65 million of goodwill, net of accumulated amortization.

    Intangible and other assets also included deferred financing costs, net of amortization, of approximately $67 million at Dec. 31, 1999. We are amortizing these financing costs over the remaining maturity periods of the related debt.

Reclassifications

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

2.  Short-Term Borrowings

Notes Payable and Commercial Paper

    Information regarding notes payable and commercial paper for the years ended Dec. 31, 1999 and 1998 is as follows (in millions, except interest rates):

Bank Lines of Credit and Compensating Bank Balances

    At Dec. 31, 1999, Xcel Energy and its subsidiaries had approximately $2 billion in credit facilities with several banks. Arrangements by Xcel Energy and its subsidiaries for committed lines of credit are maintained by a combination of fee payments and compensating balances.

    PSCo and its subsidiaries have entered into a credit facility with several banks providing $300 million in committed bank lines of credit. The credit facility, which is used primarily to support the issuance of commercial paper by PSCo and PSCCC, alternatively provides for direct borrowings thereunder. 1480 Welton, Inc. and PSRI are provided access to the credit facility with direct borrowings guaranteed by PSCo. The facility expires Nov.17, 2000. Additionally, PSCo has a credit facility, which provides $300 million in committed lines of credit and expires on June 23, 2000. SPS has two credit facilities, which provide $250 million in committed bank lines of credit, each with a commitment termination date of Feb. 25, 2000. As of Dec. 31, 1999, PSCo had used $355.6 million and SPS had used $181 million of the total capacity available under their respective committed lines of credit.

    PSCo and SPS may borrow under uncommitted preapproved lines of credit upon request; however, the banks have no firm commitment to make such loans. Individual PSCo arrangements for uncommitted bank lines of credit totaled $150 million at Dec. 31, 1999, none of which were used or outstanding.

    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,

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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. NSP-Minnesota had $420 million and $114 million of commercial paper outstanding at the end of 1999 and 1998, respectively.

    At the end of 1999, banks provided $550 million of credit lines to NRG. At Dec. 31, 1999, NRG had borrowed $340 million against these lines.

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

3.  Long-Term Debt

    Except for minor exclusions, all property of Xcel Energy's utility subsidiaries is subject to the liens of the first mortgage indentures, which are contracts between the companies and their bond holders. This property is also security for other debt obligations of Xcel Energy, as indicated in Consolidated Statement of Capitalization. Additionally, the SPS Indenture provides for certain restrictions on the payment of dividends by SPS. In addition, certain SPS payments under its pollution control obligations are pledged to secure obligations of the Red River Authority of Texas.

    The annual sinking-fund requirements of NSP-Minnesota and NSP-Wisconsin's first mortgage indentures are the amounts necessary to redeem 1 percent of the highest principal amount of each series of first mortgage bonds at any time outstanding, excluding series issued for pollution control and resource recovery financings and certain other series totaling $1 billion.

    The sinking fund requirements relate to NSP-Minnesota, NSP-Wisconsin, PSCo and Cheyenne and they expect to satisfy substantially all of their sinking fund obligations in accordance with the terms of their respective indentures through the application of property additions. SPS has no significant sinking fund requirements.

    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 2011 series bonds are redeemable upon seven days notice at the option of the bondholder. NSP-Minnesota also is potentially liable for repayment of the 2019 series when the bonds are tendered, which occurs each time the variable interest rates change. The principal amount of all of these variable rate bonds outstanding represents potential short-term obligations and, therefore, is reported under current liabilities on the Balance Sheets.

    Maturities and sinking-fund requirements for Xcel Energy's long-term debt are:

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4.  Preferred Stock

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

    PSCo has 10 million shares of cumulative preferred stock, $0.01 par value authorized. This preferred stock may be issued from time to time in such series and having such designations, preferences, limitations and relative rights as the Board of Directors may determine. At Dec. 31, 1999 and 1998, PSCo had no shares of preferred stock outstanding.

    SPS has 10 million shares of cumulative preferred stock, $1.00 par value authorized. This preferred stock may be issued from time to time in such series and having such designations, preferences, limitations and relative rights as the Board of Directors may determine. At Dec. 31, 1999 and 1998, SPS had no shares of preferred stock outstanding.

5.  Mandatorily Redeemable Preferred Securities of Subsidiary Trusts

    In 1998, PSCo Capital Trust I, a wholly owned special purpose subsidiary trust of PSCo, issued 7,760,000 shares of its 7.60 percent Trust Originated Preferred Securities for $194 million. The sole asset of the trust is $200 million principal amount of PSCo's 7.60 percent Deferrable Interest Subordinated Debentures, due June 30, 2038. Holders of the securities are entitled to receive quarterly dividends at an annual rate of 7.60 percent of the liquidation preference value of $25. The securities are redeemable at the option of PSCo on and after May 11, 2003, at 100 percent of the principal amount outstanding plus accrued interest. In addition to PSCo's obligations under the Subordinated Debentures, PSCo has agreed, pursuant to a guarantee issued to the trust and the provisions of the trust agreement establishing the trust, to guarantee, on a subordinated basis, payment of distributions on the preferred securities (but not if the trust does not have sufficient funds to pay such distributions) and to pay all of the expenses of the trust (collectively, the Back-up Undertakings). Considered together, the Back-up Undertakings constitute a full and unconditional guarantee by PSCo of the trust obligations under the preferred securities.

    In 1996, Southwestern Public Service Capital I, a wholly owned special purpose subsidiary trust of SPS, issued $100 million of its 7.85 percent Trust Preferred Securities, Series A. The sole asset of the trust is $103 million principal amount of SPS's 7.85 percent Deferrable Interest Subordinated Debentures, Series A, due Sept. 1, 2036. The securities are redeemable at the option of SPS on and after Oct. 21, 2001, at 100 percent of the principal amount plus accrued interest. In addition to SPS's obligations under the Subordinated Debentures, SPS has agreed, pursuant to a guarantee issued to the trust, the provisions of the trust agreement establishing the trust and a related expense agreement, to guarantee, on a subordinated basis, payment of distributions on the preferred securities (but not if the trust does not have sufficient funds to pay such distributions) and to pay all of the expenses of the trust. Considered together, the Back-up Undertakings constitute a full and unconditional guarantee by SPS of the trust obligations under the preferred securities.

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

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

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6.  Nuclear Obligations

Fuel Disposal

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

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

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

    Without a DOE facility, NSP-Minnesota has been providing, with regulatory and legislative approval, its own temporary on-site storage facilities at its Monticello and Prairie Island nuclear plants. With the dry cask storage facilities approved in 1994, management 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. We are 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, we could seek interim storage at this or another contracted private facility, if available.

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

Plant Decommissioning

    Decommissioning of NSP-Minnesota's nuclear facilities is planned for the years 2010-2022, using the prompt dismantlement method. We are currently 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 Xcel Energy's financial statements.

    The FASB has proposed new accounting standards, which, if approved, would require the full accrual of nuclear plant decommissioning and other site exit obligations no sooner than 2002. Using

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Dec. 31, 1999, estimates, 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. We have 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, we record annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Since the costs are expected to be paid in 2010-2022, funding presumes that current costs will escalate in the future at a rate of 4.5 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant recovery period. This annuity approach uses an assumed rate of return on funding, which is currently 6 percent, net of tax, for external funding and approximately 8 percent, net of tax, for internal funding.

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

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

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

    Decommissioning expenses recognized include the following components:

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

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

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7. Joint Plant Ownership

    The investments by Xcel Energy's utility subsidiaries in jointly-owned plants and the related ownership percentages as of Dec. 31, 1999, are (in thousands):

		Plant in Service			Accumulated Depreciation			Construction Work in Progress			Ownership %
NSP-Minnesota:
Sherco Unit 3		$	607,347		$	232,645		$	—		59.0
PSCo:
Hayden Unit 1			77,594			33,943			586		75.5
Hayden Unit 2			58,478			37,473			16,576		37.4
Hayden Common Facilities			29,907			1,395			2,484		53.1
Craig Units 1 & 2			57,710			27,927			—		9.7
Craig Common Facilities Units 1,2 & 3			20,810			7,747			52		6.5 - 9.7
Transmission Facilities, Including Substations			81,391			26,025			289		42.0 - 73.0
		$	933,237		$	367,155		$	19,987

    The PSCo assets include approximately 320 megawatts of net dependable generating capacity. PSCo is responsible for its proportionate share of operating expenses (reflected in the Consolidated Statements of Income) and construction expenditures. The increase in plant in service in 1999 and the construction work in progress amounts for Hayden Unit 1, Hayden Unit 2 and Hayden Common Facilities, including construction expenditures for installing emission control equipment for these facilities, are discussed in Note 14 Commitments and Contingencies—Environmental Matters.

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

8. Income Taxes

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

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

    Xcel Energy management intends to indefinitely reinvest earnings from foreign operations. Accordingly, U.S. income taxes and foreign withholding taxes have not been provided on a cumulative amount of unremitted earnings of foreign subsidiaries of approximately $201 million and $119 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 part by foreign tax credits. Thus, it is not practicable to estimate the amount of tax that might be payable.

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

9. Common Stock and Incentive Stock Plans

Incentive Stock Plans

    Xcel Energy and its subsidiaries have incentive compensation plans, which provide for annual and long-term incentive awards for key employees. The weighted average number of Xcel Energy common and potentially dilutive shares outstanding includes the dilutive effect of stock options and other stock

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awards based on the treasury stock method. For the periods presented, these plans are those of the predecessor companies NSP and NCE. Stock options issued under NCE plans have been adjusted for the 1.55 exchange ratio.

    A summary of the Xcel Energy's stock options at Dec. 31, 1999, 1998 and 1997, and changes during the years then ended is presented in the table below:

		1999					1998					1997
Stock Options and Performance Awards		Shares		Average Price			Shares		Average Price			Shares		Average Price
(Thousands of shares)
Outstanding at beginning of year		6,156		$	26.15		5,439		$	24.92		2,976		$	21.57
Granted		2,545			22.64		1,456			29.19		3,193			27.19
Exercised		(90	)		18.72		(636	)		22.36		(642	)		20.83
Forfeited		(111	)		30.10		(94	)		28.15		(66	)		23.42
Expired		(10	)		25.64		(9	)		23.24		(22	)		25.47
Outstanding at end of year		8,490			25.12		6,156			26.15		5,439			24.92
Exercisable at end of year		5,301			25.84		4,405			25.14		2,353			21.89

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

			Range of Exercise Prices
			$16.60 - $20.30			$20.40 - $25.50			$26.60 - $30.70
Options Outstanding (a):
	Number outstanding at Dec. 31, 1999			1,913,166			1,812,157			4,752,371
	Weighted average remaining contractual life (years)			7.8			5.3			7.6
	Weighted average exercise price		$	19.94		$	23.08		$	27.86
Options Exercisable:
	Number exercisable at Dec. 31, 1999			367,971			1,812,157			3,108,246
	Weighted average exercise price		$	18.49		$	23.08		$	27.77

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(a)

There were also 12,197 other awards outstanding at Dec. 31, 1999.

    In addition to granting stock options, NSP's incentive plans granted 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. Xcel Energy holds the stock until restrictions lapse; 50 percent of the stock vests one year from the date of the award and the other 50 percent vests two years from the date of the award. We reinvest dividends on the shares we hold while restrictions are in place. Restrictions also apply to the additional shares acquired through dividend reinvestment. NSP has granted the following restricted stock awards under its plan: 52,688 shares in 1999, 49,651 shares in 1998 and 51,790 shares in 1997. Compensation expense related to these awards was immaterial.

    The NCE/NSP merger did not constitute a change in control under the NCE incentive plans and, therefore, there will be no accelerated vesting for stock options issued under the NCE plan. When the NCE/NSP Merger was consummated, outstanding NCE stock options were converted to Xcel options at a rate of 1.55 Xcel options for every NCE option. The NCE/NSP merger represented a change in

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control under the NSP incentive plan and, therefore, all unvested stock options and restricted stock awards under that plan became fully vested and exercisable as of the merger date.

Dividend Restrictions

    Xcel Energy's Articles of Incorporation and first mortgage indenture include certain restrictions on paying cash dividends on common stock. Even with these restrictions, Xcel Energy could have paid more than $2.2 billion in additional cash dividends on common stock at Dec. 31, 1999.

10. Benefit Plans and Other Postretirement Benefits

    Xcel Energy offers the following benefit plans to its benefit employees. Approximately 42 percent of benefit employees are represented by several local labor unions under several collective-bargaining agreements. NSP-Minnesota and NSP-Wisconsin have approximately 3,204 union employees covered under a collective-bargaining agreement, which expires at the end of 2004. PSCo has approximately 1,911 union employees covered under a collective-bargaining agreement, which expires in May 2003. SPS has approximately 784 union employees covered under a collective-bargaining agreement, which expires in October 2002.

Pension Benefits

    Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all utility employees. Benefits are based on a combination of years of service, the employee's average pay and Social Security benefits.

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

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    A comparison of the actuarially computed pension benefit obligation and plan assets at Dec. 31, 1999 and 1998 for all Xcel Energy plans on a combined basis, is presented in the following table (in thousands).

    The components of net periodic pension cost (credit) for Xcel Energy plans are as follows (in thousands):

			1999			1998			1997
Service cost			$	63,674		$	55,545		$	46,098
Interest cost				154,619			145,574			140,978
Expected return on plan assets				(259,074	)		(233,191	)		(209,926	)
Curtailment				—			—			126
Amortization of transition asset				(7,314	)		(7,314	)		(7,314	)
Amortization of prior-service cost				17,855			6,209			3,502
Amortization of net gain				(40,217	)		(30,607	)		(23,157	)
Net periodic pension cost (credit) under SFAS 87			$	(70,457	)	$	(63,784	)	$	(44,693	)
Credits not recognized due to ratemaking				36,469			35,545			30,862
Net benefits cost (credit) recognized for financial reporting			$	(33,988	)	$	(28,239	)	$	(13,831	)

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    Additionally, Xcel Energy maintains noncontributory defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of Xcel Energy's operating cash flows.

Defined Contribution Plans

    Xcel Energy maintains 401(K) and other defined contribution plans that cover substantially all employees. Total contributions to these plans were approximately $21 million annually in 1999, 1998 and 1997.

    Xcel Energy has a leveraged ESOP that covers substantially all employees of NSP-Minnesota and NSP-Wisconsin. Xcel Energy makes contributions to this noncontributory, defined contribution plan to the extent we realize a tax savings from dividends paid on certain ESOP shares. ESOP contributions have no material effect on Xcel Energy earnings because the contributions are essentially offset by the tax savings provided by the dividends paid on ESOP shares. Xcel Energy allocates leveraged ESOP shares to participants when it repays ESOP loans with dividends on stock held by the ESOP.

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

Postretirement Health Care

    Xcel Energy has contributory health and welfare benefit plans that provide health care and death benefits to almost all Xcel Energy retirees. The NSP plan was terminated for nonbargaining employees retiring after 1998 and for bargaining employees after 1999.

    In conjunction with the 1993 adoption of SFAS 106, Xcel Energy elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.

    Regulators for nearly all of Xcel Energy's retail and wholesale utility customers have allowed rate recovery of accrued benefit costs under SFAS 106. PSCo transitioned to full accrual accounting for SFAS 106 costs between Jan. 1, 1993 and Dec. 31, 1997, consistent with the accounting requirements for rate regulated enterprises. The Colorado jurisdictional SFAS 106 costs deferred during the transition period are being amortized to expense on a straight line basis over the 15-year period from 1998 to 2012. NSP-Minnesota also transitioned to full accrual accounting for SFAS 106 costs, with regulatory differences fully amortized prior to 1997.

    Additionally, certain state agencies, which regulate Xcel Energy's utility subsidiaries, have issued guidelines related to the funding of SFAS 106 costs. SPS is required to fund SFAS 106 costs for Texas and New Mexico jurisdictional amounts collected in rates and PSCo and Cheyenne are required to fund SFAS 106 costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. Minnesota and Wisconsin retail regulators require external funding to the extent it is tax advantaged. Plan assets held in external funding trusts principally consist of investments in equity mutual funds, fixed securities and cash equivalents.

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    A comparison of the actuarially computed benefit obligation and plan assets at Dec. 31, 1999 and 1998 for all Xcel Energy postretirement healthcare plans is presented in the following table (in thousands):

    The assumed health care cost trend rate for 1999 is approximately 8.0 percent, decreasing to 5.5 percent in 2004 and to 4.25 percent in 2007. A 1 percent increase in the assumed health care cost trend rate would increase the estimated total accumulated benefit obligation for Xcel Energy by $49.6 million, and the service and interest cost components of net periodic postretirement benefit costs by $4.3 million. A 1 percent decrease in the assumed health care cost trend rate would decrease the estimated total accumulated benefit obligation for Xcel Energy by $41.5 million, and the service and interest cost components of net periodic postretirement benefit costs by $3.5 million.

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    The components of net periodic postretirement benefit cost of all Xcel Energy's plans are as follows (in thousands):

11. Investments Accounted for by the Equity Method

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

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    Summarized financial information for these projects, including interests owned by Xcel Energy and other parties, is as follows for the years ended Dec. 31:

Results of Operations

Financial Position

12. Regulatory Matters

Electric Utility Matters

Restructuring Legislation

    SPS is an integrated electric utility and serves approximately 385,000 retail customers in portions of the states of Texas, New Mexico, Oklahoma and Kansas. Over 97 percent of SPS' retail customers, sales and revenues are in Texas and New Mexico. SPS serves wholesale customers within its service territory that comprise approximately 30-35 percent of total electric revenues and Kwh sales. Restructuring legislation has been enacted in Texas and New Mexico, which may have a significant financial impact on the financial position, results of operations and cash flows of SPS and Xcel Energy. The Texas and New Mexico restructuring legislation is summarized in Note 2 to Exhibit 99.03 of this report.

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PSCo Performance Based Regulatory Plan (PBRP)

    PSCo's base electric rates are based on traditional cost-of-service ratemaking principles. The CPUC established a performance based regulatory plan in connection with the CPUC's decision to approve the PSCo/SPS merger. The major components of this regulatory plan include the following:

•

an annual electric department earnings test with the sharing of earnings in excess of an 11 percent return on equity for the calendar years 1997-2001;



•

a Quality Service Plan (QSP) that provides for refunds to customers if PSCo does not achieve certain performance measures relating to electric reliability, customer complaints and telephone response to inquiries; and



•

an ICA that provides for the sharing of energy costs and savings relative to an annual target cost/ delivered Kwh.

    PSCo has recorded an estimated customer refund obligation under the earnings test for the calendar years 1997 to 1999. In April of each year following the measurement period, PSCo files its proposed rate adjustment under the PBRP. The CPUC conducts proceedings to review and approve these rate adjustments annually. Since July 1998, PSCo has been refunding amounts related to the sharing of earnings in excess of 11 percent return on equity to customers. PSCo has recorded customer refund obligations for its earnings test of approximately $15 million for 1997, $8 million for 1998 and a preliminary estimate of $17 million for 1999. Final determinations of amounts to be refunded for 1998 and 1999 have not been made.

    In 1999, PSCo did not achieve all of the minimum service performance measures under the QSP, due in part to circumstances outside of its control. PSCo recorded an estimated refund obligation of approximately $3.6 million in 1999. PSCo has filed its report for the year ended 1999 with the CPUC addressing the calculated amount of the refund. Final approval by the CPUC is pending.

    Additionally, PSCo agreed to freeze base electric rates after the PSCo/SPS merger rate reductions for the period through Dec. 31, 2001, with the flexibility to make certain other rate changes, including those necessary for the recovery of DSM, QF capacity costs and decommissioning costs. The freeze in base electric rates does not prohibit PSCo from filing a general rate case or deny any party the opportunity to initiate a complaint or show cause proceeding.

SPS Electric Cost Adjustment Mechanisms

    Substantially all fuel and purchased power costs are recoverable from utility customers, as determined on a jurisdictional basis, using approved cost adjustment mechanisms.

Texas

    The PUCT's regulations require periodic examination of SPS's fuel and purchased power costs, the efficiency of the use of such fuel and purchased power, fuel acquisition and management policies and purchase power commitments. SPS is required to file an application for the PUCT to retrospectively review, at least every three years, the operations of a utility's electricity generation and fuel management activities. In June 1998, SPS filed its reconciliation for the generation and fuel management activities totaling approximately $690 million, for the period from January 1995 through December 1997. For this same period, SPS had approximately $21.4 million in under-recovered fuel costs associated with the Texas retail jurisdiction. SPS has entered into a settlement agreement with the

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General Counsel of the PUCT, which, if approved, would provide for the recovery of substantially all fuel costs. The final outcome of this fuel reconciliation proceeding is pending. Various parties in the proceedings are contesting the settlement agreement, which includes the recovery of the Thunder Basin costs discussed below.

    SPS was named as a defendant in a case entitled Thunder Basin Coal Co. vs. Southwestern Public Service Co. In 1994, the jury returned a verdict in favor of Thunder Basin and awarded damages of approximately $18.8 million. SPS appealed the judgment and, in 1997, that Court found in favor of Thunder Basin and upheld the judgment. The judgment including interest and court costs totaling approximately $22.3 million was paid in 1997.

New Mexico

    The NMPRC regulations provide for a fuel and purchased power cost adjustment clause and a fixed annual fuel factor for SPS's New Mexico retail jurisdiction. SPS files monthly and annual reports of its fuel and purchased power costs with the NMPRC, which include the current over/under fuel collection calculation, plus interest. In addition, SPS revises its fixed fuel factor annually to recover projected fuel and purchase power costs as well as any over/under fuel cost balance for the current year. SPS is required to petition for a change in the fixed fuel factor if the over/under recovery balance reaches $5 million. New Mexico's over/under calculation, plus interest, is similar to the Texas fixed fuel factor calculation.

SPS New Mexico Rate Case

    In 1997, the NMPRC issued an order investigating SPS's rates. In the order, the NMPRC determined that because of the rapid changes occurring in the electric industry, the NMPRC would require rate case filings by the major electricity suppliers who have not adopted a plan to provide retail open access and customer choice of suppliers. SPS made a compliance filing in May 1998 and subsequently entered into an uncontested stipulation agreement settling the rate investigation case. As part of this settlement, SPS instituted a $6 million annual reduction in base rates for certain retail customers and implemented full normalization in its accounting for income taxes with recovery of the New Mexico jurisdictional portion of the tax regulatory asset over 16.8 years. The NMPRC approved the stipulation and the new rates became effective Dec. 30, 1998.

NCE/NSP Merger Rate Filings

    The discussion below summarizes the significant results of the state regulatory approvals in Xcel Energy's largest utility jurisdictions in Colorado, Minnesota, Texas and New Mexico.

Colorado

    The major provisions of the CPUC decision approving the NCE/NSP merger include:

•

PSCo will reduce its retail electric rates by $11 million annually for the two-year period from July 1, 2000, through June 30, 2002;



•

PSCo will file a combined electric and gas rate case in early 2002 with new rates anticipated to be effective Jan. 1, 2003;

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•

Merger costs will be capped at $30 million and amortized for ratemaking purposes of the period July 1, 2000, to Dec. 31, 2003; and



•

the PBRP and the QSP currently in effect will continue through 2006 with modifications to cap the electric department earnings at 10.5 percent return on equity for 2002, no earnings sharing in 2003 since new base rates would have recently been established, and an increase in potential refunds if quality standards are not met, including a QSP for natural gas operations.

Minnesota

    The major provisions of the agreements approved by the MPUC include the following:

•

NSP will reduce its Minnesota electric rates by $10 million per year, or approximately 0.6 percent less than current levels, for 2001-2005;



•

NSP's electric rates may not be increased through 2005, except under limited circumstances; and



•

NSP will not seek recovery of certain merger cost from customers, to meet various quality standards and certain provisions affecting the regulatory oversight of Xcel Energy.

Texas

    The major provisions of the regulatory plan included in the Stipulation, include the following:

•

guaranteed merger savings credits of $400,000 per month and the amortization of merger costs for the period from the effective date of the merger through Dec. 31, 2005;



•

retention of the current fuel recovery mechanism to pass along fuel cost savings to retail customers; and



•

an agreement to comply with various new service quality and reliability standards, covering service installations and upgrades, light replacements, customer service call center and electric service reliability.

New Mexico

    The major provisions of the NMPRC decision approving the merger are as follows:

•

guaranteed merger savings credits of $65,000 per month;



•

an equal sharing of the net non-fuel operating and maintenance savings among retail customers and shareholders;



•

a 50 percent recovery of merger related transaction and transition costs;



•

retention of the current fuel recovery mechanism to pass along fuel cost savings to retail customers.



•

SPS will not pass along any negative rate impacts of the NCE/NSP merger.

    We estimate that SPS's New Mexico retail customers will receive approximately $4.0 million of merger savings over the period ending Dec. 31, 2004.

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Gas Utility Matters

PSCo Rate Cases

    In 1998, PSCo filed a retail gas rate case with the CPUC requesting an annual increase in rates of approximately $23.4 million. The request for a rate increase reflects revenues for additional plant investment, a 12.0 percent return on equity and the recovery of incremental year 2000 costs. In 1999, the CPUC approved an increase in base rates of approximately $15 million with an 11.25 percent return on equity, effective July 1, 1999. PSCo was also allowed recovery of certain environmental costs. Prudently incurred year 2000 costs will be recovered under a separate mechanism beginning in 2000.

    In 1996, PSCo filed a retail rate case with the CPUC requesting an annual increase in its jurisdictional gas department revenues equal to approximately $34 million. In early 1997, the CPUC approved an overall increase of approximately $18 million with an 11.25 percent return on equity, but disallowed the recovery of certain postemployment benefit costs under SFAS 112. During 1997, PSCo filed a petition with the Denver District Court appealing the CPUC's decision. The Denver District Court affirmed the CPUC disallowance of SFAS 112 costs in 1999 and PSCo subsequently filed a petition with the Colorado Supreme Court to appeal the Denver District Court's decision. In the event that PSCo is not successful in its appeal(s), including pursuing regulatory recovery, $23 million of deferred SFAS 112 costs will be written off.

Planned Closure of PSCo Underground Gas Storage Facility

    PSCo filed an application with the CPUC requesting authority to shut down and abandon an underground natural gas storage facility during 2001, after 40 years of operation. The application seeks approval of a formal decommissioning plan. The plan outline PSCo's proposal to plug and abandon the wells that are currently being used to inject and withdraw gas from the mine and requests approval of the costs to decommission and shut down the facility, which are currently estimated at approximately $8.6 million. An application to recover these costs and remaining plant investments from the ratepayers will be filed with the CPUC in a separate future proceeding.

PSCo Unbundling and Deregulation of the Retail Natural Gas Supply Business

    During 1999, a bill allowing natural gas public utilities to voluntarily submit plans to the CPUC to open their markets and enable customers to choose their natural gas supplier was approved by the Colorado Legislature and by the Governor. Currently, PSCo provides a traditional bundled gas service with rates designed for the recovery of actual gas costs through the GCA and for providing transportation and delivery services. Delivery of natural gas will continue to be regulated, with delivery companies required to offer nondiscriminatory pipeline access to competitors. PSCo will continue to be subject to the reporting requirements of SFAS 71 as a regulated distribution company. PSCo has not filed a plan to open its natural gas supply business to competition and continues to evaluate its business opportunities for doing so.

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13.  Financial Instruments

Fair Values

    The estimated Dec. 31 fair values of Xcel Energy's recorded financial instruments are as follows:

    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 Xcel Energy's long-term investments, mainly debt securities in an external nuclear decommissioning fund, are estimated based on quoted market prices for those or similar investments. The fair value of Xcel Energy's long-term debt and the mandatorily redeemable preferred securities are estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.

    The fair value estimates presented are based on information available to management as of Dec. 31, 1999 and 1998. These fair value estimates have not been comprehensively revalued for purposes of these financial statements since that date, and current estimates of fair values may differ significantly from the amounts presented herein.

Guarantees

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

    Xcel Energy has entered into a construction contract guarantee that assures Quixx's performance under its engineering, procurement, and construction contract with Borger Energy Associates, L.P. (BEA). Quixx, which owns 45 percent of BEA, is constructing a 230-megawatt cogeneration facility at a Phillips Petroleum site near Borger, Texas. The maximum aggregate amount of this guarantee at Dec. 31, 1999, was $88.4 million. This maximum amount decreases to $25.0 million at commercial operation of the facility and remains in effect for a period of no longer than 24 months before expiring. Based upon the current status of construction of the facility, this guarantee is not expected to have any financial impact on Xcel Energy.

    As of Dec. 31, 1999, Xcel Energy had $147.9 million of guarantees outstanding to e prime. These guarantees were made to facilitate e prime's gas marketing and trading activities.

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    In connection with an agreement for the sale of electric power, SPS guaranteed certain obligations of a customer totaling $32 million at Dec. 31, 1999. These obligations related to the construction of certain utility property that, in the event of default by the customer, would revert to SPS.

    Young Storage entered into a $30.7 million credit agreement with various lending institutions on March 26, 1999, with a stated maturity date of March 31, 2014. As support for the loan, Xcel Energy has provided a letter of credit of approximately $0.8 million to fulfill debt service reserve requirements under the loan. This loan refinanced the initial $32 million credit facility originally entered into on June 27, 1995, which was incurred for the development and construction of an underground natural gas storage facility in northeastern Colorado. Separately, Xcel Energy has guaranteed up to $4.5 million to cover costs of expenses related to the project.

    Xcel Energy had $10 million of guarantees outstanding for Xcel Cadence (formerly New Century Cadence) as of Dec. 31, 1999. These guarantees relate to the capital requirements and operations of Cadence Network LLC.

Derivatives

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

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

    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.

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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.



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



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

    SPS has an interest rate swap agreement, which, in effect, fixes the interest rate on a $25 million notional amount of tax exempt bonds at 6.435 percent. Amounts paid or received under this agreement are accrued as interest rates change and are recognized over the life of the agreement as an adjustment to interest expense. SPS is exposed to interest rate risk in the event of nonperformance by counterparties; however, SPS does not anticipate such nonperformance.

    Xcel Energy's regulated Power Marketing division uses energy futures contracts, along with physical supply, to hedge market risk in the energy market. At Dec. 31, 1999, the notional amount of

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energy futures contracts was immaterial and management believes that the risk of counterparty nonperformance with regard to any of the hedge transactions is not significant.

    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.

    At Dec. 31, 1999, e prime's retail gas marketing business held notional long volumetric positions of approximately 7.0 million Mmbtus of natural gas related to these financial instruments that had related unrealized losses of approximately $1.4 million. At Dec. 31, 1998, e prime held notional long volumetric positions of approximately 14.2 million Mmbtus of natural gas related to these financial instruments that had related unrealized losses of approximately $6.4 million. The weighted average maturity of these instruments is less than one year.

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

Letters of Credit

    Xcel Energy and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. In addition, NRG uses letters of credit for nonregulated equity commitments, collateral for credit agreements, fuel purchase and operating commitments, and bids on development projects. At Dec. 31, 1999, there were $140 million in letters of credit outstanding, including $116 million related to NRG commitments. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

14.  Commitments and Contingent Liabilities

Legislative Resource Commitments

    In 1994, NSP-Minnesota received Minnesota legislative approval for additional on-site temporary spent fuel storage facilities at its Prairie Island plant, provided NSP-Minnesota satisfies certain requirements. Seventeen dry cask containers were approved. As of Dec. 31, 1999, NSP-Minnesota had loaded nine casks. The Minnesota Legislature established several energy resource and other commitments for NSP-Minnesota to obtain the Prairie Island temporary nuclear fuel storage facility approval. These commitments can be met by building, purchasing or, in the case of biomass, converting generation resources.

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

    During 1997 and 1998, NSP-Minnesota 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

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December 1999, NSP-Minnesota 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-Minnesota in relation to its efforts to meet the mandate, including whether NSP-Minnesota intends to exercise an option to increase the megawatt size of one of the contracts. Although the agreements met the requirements for biomass scheduled to be operational by Dec. 31, 2001, and Dec. 31, 2002, due to various delays the actual operational dates of the biomass facilities may be later than scheduled.

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

Capital Commitments

    As discussed in Liquidity and Capital under Management's Discussion and Analysis, the estimated cost, as of Dec. 31, 1999, of the capital expenditure programs of Xcel Energy and its subsidiaries and other capital requirements is approximately $4.2 billion in 2000, $1.9 billion in 2001 and $1.7 billion in 2002.

    The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in the electric system projected load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy's long-term energy needs. In addition, Xcel Energy's ongoing evaluation of merger, acquisition and divestiture opportunities to support corporate strategies, address restructuring requirements and comply with future requirements to install emission control equipment may impact actual capital requirements.

    Xcel Energy's capital expenditures include approximately $2.7 billion in 2000 for NRG investments and asset acquisitions. NRG's future capital requirements may vary significantly. For 2000, NRG's capital requirements reflect expected acquisitions of existing generation facilities, including Cajun, Killingholme A and the Conectiv fossil assets.

Tax Matters

    PSRI, a subsidiary of PSCo, owns and manages permanent life insurance policies on certain past and present employees. These COLI policies were entered into prior to July 1, 1986. In 1996, Congress passed legislation to phase out the tax benefits with certain COLI policies; however, PSRI's policies were grandfathered under this legislation. In August 1998, the IRS issued a Notice of Proposed Adjustment proposing to disallow the 1993 and 1994 deductions of interest expense related to policy loans on the COLI policies totaling approximately $54.6 million. A Request for Technical Advice from the IRS National Office with respect to the proposed adjustment is pending.

    Management is vigorously contesting this issue. PSRI has not recorded any provision for income tax or interest expense related to this matter and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years. Management believes that PSRI's tax deduction of interest expense on life insurance policy loans was in full compliance with IRS

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regulations and believes that the resolution of this matter will not have a material adverse impact on Xcel Energy's financial position, results of operations or cash flows.

Leases

    Xcel Energy's subsidiaries lease various equipment and facilities used in the normal course of business, some of which are accounted for as capital leases. Expiration of the capital leases range from 2000 to 2025. The net book value of property under capital leases was approximately $57 million and $40 million at Dec. 31, 1999 and 1998, respectively. Assets acquired under capital leases are recorded as property at the lower of fair-market value or the present value of future lease payments and are amortized over their actual contract term in accordance with practices allowed by regulators. The related obligation is classified as long-term debt. Executory costs are excluded from the minimum lease payments.

    Rental expense under operating lease obligations was approximately $57 million, $49 million and $68 million for 1999, 1998 and 1997, respectively. Future commitments under these leases generally decline from current levels.

Nuclear Insurance

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

    NSP purchases insurance for property damage and site decontamination cleanup costs from 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.

Fuel Contracts

    Xcel Energy 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 2017. In total, Xcel Energy is committed to the minimum purchase of approximately $2.1 billion of coal, $21 million of nuclear fuel and $706 million of natural gas and related

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transportation, or to make payments in lieu thereof, under these contracts. In addition, NSP is required to pay additional amounts depending on actual quantities shipped under these agreements.

    Xcel Energy'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 most fuel costs.

Purchase Power Agreements

    The utility subsidiaries of Xcel Energy have entered into agreements with utilities, QFs and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. NSP-Minnesota, PSCo and SPS have various pay-for-performance contracts with expiration dates through the year 2033. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations, and energy payments based on actual power taken under the contracts. The capacity and energy costs are recovered through base rates and other cost recovery mechanisms. Additionally, NSP-Minnesota, PSCo, SPS and Cheyenne have long-term purchased power contracts with various regional utilities expiring through 2018.

    NSP-Minnesota has a 500-megawatt participation power purchase commitment with Manitoba Hydro, which expires in 2005. The cost of this agreement is based on 80 percent of the costs of owning and operating NSP-Minnesota's Sherco 3 generating plant, adjusted to 1993 dollars. In addition, NSP-Minnesota and Manitoba Hydro have seasonal diversity exchange agreements and there are no capacity payments for the diversity exchanges. These commitments represent about 17 percent of Manitoba Hydro's system capacity and account for approximately 10 percent of NSP-Minnesota's 2000 electric system capability. The risk of loss from nonperformance by Manitoba Hydro is not considered significant, and the risk of loss from market price changes is mitigated through cost-of-energy rate adjustments.

    At Dec. 31, 1999, the estimated future payments for capacity that the utility subsidiaries of Xcel Energy are obligated to purchase, subject to availability, are as follows (in thousands):

Environmental Contingencies

    Xcel Energy and its subsidiaries are subject to various environmental laws, including regulations governing air and water quality, the storage of natural gas and the storage and disposal of hazardous or toxic wastes. Xcel Energy and its subsidiaries assess, on an ongoing basis, measures to ensure compliance with laws and regulations related to air and water quality, hazardous materials and

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hazardous waste compliance and remediation activities. Changes to environmental regulations, interpretations or enforcement policies may impact the future construction and operation of Xcel Energy's electric generation, transmission and distribution systems and gas transportation, storage and distribution systems.

    Other long-term liabilities include an accrual of $39 million, and other current liabilities include an accrual of $10 million, at Dec. 31, 1999, for estimated costs associated with environmental remediation. Approximately $24 million of the long-term liability and $4 million of the current liability relate to a DOE assessment for decommissioning a federal uranium enrichment facility, as discussed in Note 6. Other estimates have been recorded for expected environmental costs associated with manufactured gas plant sites and other waste disposal sites, as discussed later. These environmental liabilities do not include accruals recorded and collected from customers in rates for future nuclear fuel disposal costs or decommissioning costs related to NSP-Minnesota's nuclear generating plants. See Note 6 for further discussion of nuclear items.

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

Site Remediation

    The 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.

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



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

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

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recovered, from insurance carriers or other parties should be allowed recovery in future ratemaking. Until NSP-Minnesota is identified as a PRP, it is not possible to predict the timing or amount of any costs associated with sites, other than those discussed previously.

    NSP-Wisconsin may be involved in the cleanup and remediation at three sites, including one that NSP-Minnesota is also investigating. One site is a former transformer disposal facility in New Lisbon, Wis., and the remaining two are locations where fuel tanks were installed. The ultimate cleanup and remediation costs of these sites and the extent of NSP-Wisconsin's responsibility, if any, for sharing such costs are not known at this time, but are expected to be immaterial.

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

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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.



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



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



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

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

    NSP-Wisconsin will be involved in the cleanup and remediation at locations of former manufactured gas plants at Ashland, LaCrosse, 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 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

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properties, which include an adjacent city lakeshore park area and a small area of Lake Superior's Chequemegon Bay adjoining the park.

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

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

    Under CERCLA, the EPA identified low-level, widespread contamination from hazardous substances at the Barter Metals Company (Barter) properties located in central Denver. Because it was identified as a PRP, PSCo completed the cleanup of this site at a cost of approximately $9 million. In January 1996, in a lawsuit by PSCo against its insurance providers, the Denver District Court entered final judgment in favor of PSCo in the amount of $5.6 million for certain cleanup costs at Barter. Several appeals and cross appeals were filed by one of the insurance providers and PSCo. In September 1999, the Colorado Supreme Court held that the trial court should have allocated the damages and self-insured retentions over the entire period the facilities were in operation. Although the Colorado Supreme Court remanded the judgement to the trial court for additional proceedings, it suggested that its ruling may reduce PSCo's available recovery to approximately $1.4 million. PSCo requested recovery of environmental costs of approximately $7.7 million related to Barter over four years in its proposed Performance Based Regulatory Plan for calendar years 1998-2001 (see Note 12 Regulatory Matters).

    PSCo has identified several other sites where clean-up of hazardous substances may be required. While potential liability and settlement costs are still under investigation and negotiation, PSCo believes that the resolution of these matters will not have a material adverse effect on PSCo's financial position,

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results of operations or cash flows. PSCo will pursue the recovery of all significant costs incurred for such projects through insurance claims and/or the rate regulatory process.

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

Plant Emissions

    In 1998, the EPA published nitrogen oxide (NO_x) emission regulations affecting 22 states, including Wisconsin. The goal of the new regulations is to reduce NO_x emissions by 85 percent by May 1, 2003. Two of NSP-Wisconsin's boilers and eight of its combustion turbines may be affected by this action. If the existing boilers and combustion turbines are made compliant using retrofit technology to control NO_x emissions, it could cost NSP-Wisconsin up to $62 million for capital improvements and add $14 million each year for operation and maintenance expenses. This is the estimated cost of the most expensive alternative to achieve compliance, which is not necessarily the compliance alternative of choice. If the rules are finalized in their most stringent form, other alternatives for these older units may be deemed more cost effective than retrofitting. How the WDNR will implement the new EPA NO_x regulations and their applicability to NSP-Wisconsin are still uncertain.

    NSP-Wisconsin has joined with two other Wisconsin-based utilities as well as the Wisconsin Paper Council and Wisconsin Manufacturers and Commerce industrial organizations to request a judicial review of the EPA's final NO_x rules. NSP-Wisconsin believes that the EPA improperly included Wisconsin in the scope of the regulatory action and improperly calculated potential emissions of NO_x, reducing the allowable emission limits for the state.

    In 1999, the EPA was ordered by a federal appeals panel to suspend implementation of the NO_x rules pending further action on a lawsuit brought by another trade group. It is possible that the state of Wisconsin will either not be required to meet the more stringent NO_xrequirements 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-Minnesota is completing installation of over-fire air at the King plant to meet the NO_X emission limitations. NSP-Minnesota's capital expenditures include some costs for ensuring compliance with the Clean Air Act; other expenditures may be necessary upon EPA finalization of remaining rules. PSCo has obtained all necessary conditions to proceed with its plans to spend approximately $211 million on its Denver and Boulder metro area coal-fueled power plants to further reduce such emissions below the required regulatory levels discussed above. The cost of this emission control equipment will be recovered through rates from Colorado customers under a separate rate schedule when this equipment is placed in service.

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SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14.  Commitments and Contingent Liabilities (Continued)

    In May 1996, PSCo and the other joint owners of Hayden Station reached an agreement resolving violations alleged in complaints filed by a conservation organization, the CDPHE and the EPA against the joint owners. PSCo is the operator and owns an average undivided interest of approximately 53 percent of the station's two generating units. In connection with the settlement, the joint owners of the Hayden station were required to install emission control equipment of approximately $130 million (PSCo's portion is approximately $70 million). This equipment was installed and became operational on Units 1 and 2 during 1998 and 1999 as scheduled and required under the settlement. Additionally, the settlement included stipulated future penalties for failure to comply with specified SO2 and NOx emission levels. Based on current operations, management anticipates that it will be able to operate the units as planned.

    In October 1996, a conservation organization filed a complaint in the U. S. District Court pursuant to provisions of the Federal Clean Air Act against the joint owners of the Craig Steam Electric Generating Station located in western Colorado. Tri-State Generation and Transmission Association, Inc. is the operator of the Craig station and PSCo owns an undivided interest (acquired in April 1992) in each of two units at the station totaling approximately 9.7 percent. The plaintiff alleged that the station violated Clean Air Act requirements related to opacity. The complaint seeks, among other things, civil monetary penalties and injunctive relief. The Clean Air Act provides for penalties of up to $25,000 per day per violation, but the level of penalties imposed in any particular instance is discretionary. The parties, the EPA and the CDPHE have entered into mediation in an attempt to resolve all air quality matters related to the facility. Resolution of this matter may require the installation of additional emission control equipment. Management does not believe that any potential liability, the future impact of this litigation on plant operations, or any related cost will have a material adverse impact on PSCo's financial position, results of operations or cash flows.

    Because Xcel Energy is still in the process of implementing some provisions of the Clean Air Act, its total financial impact is unknown at this time. Capital expenditures for opacity compliance are included in the capital expenditure commitments disclosed previously. The depreciation of these capital costs will be subject to regulatory recovery in future rate proceedings.

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

Legal Claims

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

    On Dec. 11, 1998, a gas explosion in St. Cloud, Minn., killed four people, including two NSP employees, injured approximately 14 people and damaged several buildings. The accident occurred as a crew from Cable Constructors Inc. (CCI) was installing fiber optic cable for Seren. Seren, CCI and Sirti, an architecture/engineering firm retained by Seren, are named as defendants in 10 lawsuits relating to the explosion. NSP is a defendant in eight of the lawsuits. NSP and Seren deny any liability for this accident. NSP has a self-insured retention deductible of $2 million with general liability

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coverage limits of $185 million. Seren's primary insurance coverage is $1 million and its secondary insurance coverage is $185 million. The ultimate cost to NSP and Seren, if any, is presently unknown.

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

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

15.  Regulatory Assets and Liabilities

    Xcel Energy's regulated subsidiaries prepare their financial statements in accordance with the provisions of SFAS 71, as discussed in Note 1. Xcel Energy believes its utility subsidiaries continued to be subject to rate regulation as of Dec. 31, 1999. However, the pending deregulation efforts underway in Xcel Energy's utility jurisdictions may preclude the use of SFAS 71 accounting in the future.

    Current accounting rules require that when deregulatory legislation is passed or when a rate order (whichever is necessary to effect change in the jurisdiction) that contains sufficient detail for an enterprise to reasonably determine how the transition plan will affect the separable portion of its business whose pricing is being deregulated is issued, the enterprise should stop applying SFAS 71 to that separable portion of its business. While legislation has been enacted in Texas and New Mexico as of Dec. 31, 1999, there were several unresolved issues that will significantly impact how and when deregulation related to the generation portion of the business will be implemented by SPS. It is expected that SPS will discontinue the application of SFAS 71 related to the generation portion of the business when the requirements noted above have been met, which is expected to occur in the year 2000 (see Note 12).

    In the event that a portion of a subsidiary's operations is no longer subject to the provisions of SFAS 71, as a result of a change in regulation or the effects of competition, Xcel Energy's subsidiaries could be required to write off that portion's regulatory assets, determine any impairment to other assets resulting from deregulation and write down any impaired assets to their estimated fair value. Depending on ratemaking treatment provided, such write-downs could have a material adverse effect on Xcel Energy's financial position, results of operations or cash flows.

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

			Remaining Amortization Period		1999			1998
(Thousands of dollars)
AFC recorded in plant(a)			Plant Lives		$	184,860		$	196,452
Conservation programs(a)			5 Years			40,868			110,155
Losses on reacquired debt			Term of Related Debt			84,190			89,380
Environmental costs			Primarily 10 Years			48,708			50,158
Unrecovered gas costs			1-2 Years			15,266			16,259
Deferred income tax adjustments			Mainly Plant Lives			28,581			57,601
Nuclear decommissioning costs			6 Years			63,835			69,490
Employees' postretirement benefits other than pension			13 Years			53,321			57,350
Employees' postemployment benefits			Undetermined			23,374			24,888
State commission accounting adjustments(a)			Plant Lives			7,641			7,370
Other			Various			16,083			20,998
	Total regulatory assets				$	566,727		$	700,101
Investment tax credit deferrals					$	136,349		$	146,460
Unrealized gains from decommissioning investments						177,578			138,613
Pension costs-regulatory differences						84,198			53,012
Conservation incentives						25,284
Fuel costs, refunds and other						18,795			20,683
	Total regulatory liabilities				$	442,204		$	358,768

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(a)

Earns a return on investment in the ratemaking process

16.  Segment and Related Information

    Xcel Energy has four reportable segments: Electric Utility, Gas Utility and two of its nonregulated energy businesses, NRG and Xcel International, both subsidiaries of Xcel Energy.

•

Xcel Energy's Electric Utility generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas, New Mexico, Wyoming, Kansas and Oklahoma. It also makes sales for resale and provides wholesale transmission service to various entities in the United States.



•

Xcel Energy's Gas Utility transmits, transports, stores and distributes natural gas and propane primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan, Arizona, Colorado and Wyoming.



•

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

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•

Xcel International's most significant holding is Yorkshire Power, a joint venture equally owned by Xcel International and a subsidiary of American Electric Power Company. Yorkshire's main business is the distribution and supply of electricity and the supply of natural gas in the U.K.

    Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the All Other category. Those primarily include a company involved in nonregulated power and gas marketing activities throughout the United States; a company that invests in and develops cogeneration and energy related projects; a company that is engaged in engineering, design construction management and other miscellaneous services, a company engaged in energy consulting, energy efficiency management, conservation programs and mass market services, an affordable housing investment company, a broadband telecommunications company and several other small companies and businesses.

    To report net income for electric and gas utility segments, Xcel Energy 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 accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies. Xcel Energy evaluates performance by each legal entity based on profit or loss generated from the product or service provided. Assets by segment are not reported to management and are not included in the disclosures that follow.

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Business Segments

1999			Electric Utility			Gas Utility			NRG			Xcel International			All Other			Reconciling Eliminations			Consolidated Total
(Thousands of dollars)
Operating revenues from external customers (b)			$	4,923,530		$	1,141,294		$	427,567			—		$	263,921			—		$	6,756,312
Intersegment revenues				1,303			11,785			963			—			121,648			(134,731	)		968
Equity in earnings (losses) of unconsolidated affiliates				—			—			68,947			44,908			(1,731	)		—			112,124
	Total revenues		$	4,924,833		$	1,153,079		$	497,477			44,908		$	383,838		$	(134,731	)	$	6,869,404
Depreciation and amortization				546,794			82,206			37,026			182			17,767			—			683,975
Financing costs, mainly interest expense				300,108			53,217			92,570			714			25,488			(19,020	)		453,077
Income tax expense (credit)				272,129			24,081			(26,416	)		(13,559	)		(62,428	)		(14,135	)		179,672
Segment net income (loss)			$	431,510		$	49,175		$	57,195		$	58,301		$	(12,127	)	$	(13,121	)	$	570,933
1998			Electric Utility			Gas Utility			NRG			Xcel International			All Other			Reconciling Eliminations			Consolidated Total
(Thousands of dollars)
Operating revenues from external customers (b)			$	4,984,506		$	1,109,953		$	98,688			—		$	285,100			—		$	6,478,247
Intersegment revenues				1,131			14,573			1,737			—			75,209			(91,722	)		928
Equity in earnings (losses) of unconsolidated affiliates				—			—			81,706			38,127			(3,848	)		—			115,985
	Total revenues		$	4,985,637		$	1,124,526		$	182,131		$	38,127		$	356,461		$	(91,722	)	$	6,595,160
Depreciation and amortization				524,703			75,753			16,320			121			14,353			—			631,250
Financing costs, mainly interest expense				262,654			44,074			50,313			745			19,635			5,865			383,286
Income tax expense (credit)				300,103			24,945			(25,654	)		(15,817	)		(28,212	)		(14,974	)		240,391
Segment net income (loss)			$	505,077		$	47,180		$	41,732		$	51,978		$	6,365			(28,002	)	$	624,330
1997			Electric Utility			Gas Utility			NRG			Xcel International			All Other			Reconciling Eliminations			Consolidated Total
(Thousands of dollars)
Operating revenues from external customers (b)			$	4,668,040		$	1,155,410		$	102,791			—		$	314,648			—		$	6,240,889
Intersegment revenues				1,301			9,938			926			—			25,819			(36,942	)		1,042
Equity in earnings (losses) of unconsolidated affiliates				—			—			26,003			35,499			(8,736	)		—			52,766
	Total revenues		$	4,669,341		$	1,165,348		$	129,720		$	35,499		$	333,731		$	(36,942	)	$	6,294,697
Depreciation and amortization				493,202			68,442			10,310			89			14,116			—			586,159
Financing costs, mainly interest expense				263,313			40,805			30,729			186			18,066			12,700			365,799
Income tax expense (credit)				269,276			30,642			(23,680	)		(1,186	)		(41,227	)		(3,196	)		230,629
Segment net income (loss)			$	415,265		$	49,318		$	21,982		$	35,946		$	(4,753	)		(18,951	)	$	498,807

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(a)

All operating revenues are from external customers located in the United States. However, Xcel International and NRG have significant equity investments for nonregulated projects outside of the United States. NRG's equity in earnings of unconsolidated affiliates, primarily independent power projects, includes $38.6 million in 1999, $29.3 million in 1998 and $27.1 million in 1997 from nonregulated projects located outside of the United States. NRG's equity investments in projects outside of the United States were $606 million in 1999, $557 million in 1998 and $517 million in 1997. All of Xcel International's equity in earnings of unconsolidated affiliates is from outside of the United States.

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17.  Summarized Quarterly Financial Data (Unaudited)

			Quarter Ended
			March 31, 1999			June 30, 1999(a)			Sept. 30, 1999			Dec. 31, 1999(a)
(Thousands of dollars, except per share amounts)
Revenue			$	1,744,155		$	1,508,776		$	1,816,339		$	1,800,134
Operating income				306,285			189,662			423,601			303,009
Net income				153,621			60,725			209,264			147,323
Earnings available for common stock				152,561			58,615			208,204			146,261
Earnings per average common share:
	Basic		$	0.46		$	0.18		$	0.63		$	0.44
	Diluted		$	0.46		$	0.18		$	0.63		$	0.44

			Quarter Ended
			March 31, 1998			June 30, 1998			Sept. 30, 1998(b)			Dec. 31, 1998(c)
(Thousands of dollars except per share amounts)
Revenue			$	1,679,122		$	1,518,326		$	1,723,820		$	1,673,892
Operating income				299,577			230,341			368,473			310,787
Net income				143,266			91,627			192,466			196,971
Earnings available for common stock				140,899			90,567			191,406			195,910
Earnings per average common share:
	Basic		$	0.44		$	0.28		$	0.59		$	0.60
	Diluted		$	0.44		$	0.28		$	0.59		$	0.60

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(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 7 cents per share, due to the disallowance of 1998 incentives. Fourth quarter results were reduced by $22 million before taxes, or 4 cents per share, due to the reversal of all income recorded through the third quarter for 1999 electric conservation program incentives. In addition, 1999 fourth quarter results include a pretax charge of $17 million, or 4 cents per share, to write off goodwill related to EMI acquisitions. Also, a pretax charge of $11 million, or 2 cents per share, was recorded in the fourth quarter of 1999 to write down an investment in CellNet common stock.

(b)

1998 results include a $22 million pretax charge, which reduced third quarter earnings by 5 cents per share, for the write-down of NRG projects.

(c)

1998 results include a $26 million pretax gain, which increased fourth quarter earnings by 5 cents per share, for a partial sale of an NRG project.

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