Item 7. Management’s Discussion and Analysis

BUSINESS SEGMENTS AND ORGANIZATIONAL OVERVIEW

Xcel Energy Inc. (Xcel Energy), a Minnesota corporation, is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). In 2003, Xcel Energy directly owned five utility subsidiaries that serve electric and natural gas customers in 11 states. These utility subsidiaries are Northern States Power Co., a Minnesota corporation (NSP-Minnesota); Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado (PSCo); Southwestern Public Service Co. (SPS) and Cheyenne Light, Fuel and Power Co. (Cheyenne). These utilities serve customers in portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Wisconsin and Wyoming. Along with WestGas InterState Inc. (WGI), an interstate natural gas pipeline, these companies comprise our continuing regulated utility operations. In January 2003, Xcel Energy sold Viking Gas Transmission Co. (Viking), an interstate natural gas pipeline company, including Viking’s interest in Guardian Pipeline, LLC. In October 2003, Xcel Energy sold Black Mountain Gas Co. (BMG), a regulated natural gas and propane distribution company. Both Viking and BMG are reported as a component of discontinued operations. In January 2004, Xcel Energy reached an agreement to sell Cheyenne, pending regulatory approval.

Xcel Energy’s nonregulated subsidiaries in continuing operations include Utility Engineering Corp. (engineering, construction and design), Seren Innovations, Inc. (broadband telecommunications services), Planergy International, Inc. (energy management solutions) and Eloigne Co. (investments in rental housing projects that qualify for low-income housing tax credits). During 2003, the board of directors of Xcel Energy approved management’s plan to exit businesses conducted by the nonregulated subsidiaries Xcel Energy International Inc. (an international independent power producer, operating primarily in Argentina) and e prime inc. (a natural gas marketing and trading company). Both of these businesses are presented as a component of discontinued operations.

During 2003, Xcel Energy also divested its ownership interest in NRG Energy, Inc. (NRG), an independent power producer. On May 14, 2003, NRG and certain of its affiliates filed voluntary petitions in the U.S. Bankruptcy Court for the Southern District of New York for reorganization under Chapter 11 of the U.S. Bankruptcy Code to restructure their debt. On Dec. 5, 2003, NRG completed its reorganization and emerged from bankruptcy. As a result of the reorganization, Xcel Energy relinquished its ownership interest in NRG. At Dec. 31, 2003, Xcel Energy reports NRG’s financial activity as a component of discontinued operations. Xcel Energy is obligated to make payments of up to $752 million to NRG in 2004 and expects to fund these payments with cash on hand and proceeds from a tax refund associated with the write-off of its investment in NRG.

See Note 3 to the Consolidated Financial Statements for further discussion of discontinued operations.

FORWARD-LOOKING STATEMENTS

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,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by Xcel Energy and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership; structures that affect the speed and degree to which competition enters the electric and natural gas markets; the higher risk associated with Xcel Energy’s nonregulated businesses compared with its regulated businesses; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; risks associated with the California power market; the items described under Factors Affecting Results of Operations; and the other risk factors listed from time to time by Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2003.

FINANCIAL REVIEW

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying Consolidated Financial Statements and Notes. All note references refer to the Notes to Consolidated Financial Statements.

RESULTS OF OPERATIONS

Summary of Financial Results

The following table summarizes the earnings contributions of Xcel Energy’s business segments on the basis of generally accepted accounting principles (GAAP). Continuing operations consist of the following:

	•		regulated utility subsidiaries, operating in the electric and natural gas segments; and
	•		several nonregulated subsidiaries and the holding company, where corporate financing activity occurs.

Discontinued operations consist of the following:

	•		the regulated natural gas businesses Viking and BMG, which were sold in 2003;
	•		NRG, which emerged from bankruptcy in late 2003, at which time Xcel Energy divested its ownership interest in NRG; and
	•		the nonregulated subsidiaries Xcel Energy International and e prime, which were classified as held for sale in late 2003 based on the decision to divest them.

Prior-year financial statements have been restated to conform to the current year presentation and classification of certain operations as discontinued. See Note 3 to the Consolidated Financial Statements for a further discussion of discontinued operations.

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(a) Not a reportable segment. Included in All Other segment results in Note 20 to the Consolidated Financial Statements.

(b) Includes tax benefit related to NRG. See Note 3 to the Consolidated Financial Statements.

The regulated utility segment contribution to income from continuing operations was lower in 2003 primarily due to higher operating costs and weather impacts, as well as share dilution. The increase in income from discontinued operations in 2003 is largely due to lower NRG-related losses compared with 2002. NRG recorded more than $3 billion of asset impairment and other charges in 2002 as it commenced its financial restructuring. Results from discontinued operations include NRG-related tax benefits in both 2003 and 2002, as discussed in the Discontinued Operations section later.

Common Stock Dilution — Dilution, primarily from common stock and convertible securities issued in 2002, reduced the utility segment earnings from continuing operations by 12 cents per share for 2003, compared with average common stock and equivalent levels in 2002. Total earnings from continuing operations were reduced by 11 cents per share for 2003, compared with 2002 share levels. In 2003 and 2002, approximately 418.9 million and 384.6 million average common shares and equivalents, respectively, were used in the calculation of diluted earnings per share.

Because the divestiture of NRG has required its reclassification to discontinued operations in 2003, as discussed later, Xcel Energy is now reporting income from continuing operations in 2003 and 2002. Under accounting requirements, the calculation of diluted earnings per share must be changed for prior periods that reported losses, in which equivalents were previously considered antidilutive. Accordingly, the average common shares assumed in the diluted earnings per share amounts for the third and fourth quarters of 2002, the year 2002 and the first three quarters of 2003 have been recalculated to assume more share dilution and are different from amounts previously reported for those periods. See Note 11 to the Consolidated Financial Statements for further discussion of the calculation of average shares and earnings per share.

Statement of Operations Analysis — Continuing Operations

The following discussion summarizes the items that affected the individual revenue and expense items reported in the Statement of Operations.

Electric Utility and Commodity Trading Margins

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel cost recovery mechanisms for retail customers in several states, most fluctuations in energy costs do not materially affect electric utility margin. The retail fuel clause cost recovery mechanism in Colorado changed in 2003. For 2002 and 2001, electric utility margins in Colorado reflect the impact of sharing energy costs and savings between customers and shareholders relative to a target cost per delivered kilowatt-hour under the retail incentive cost adjustment (ICA) ratemaking mechanism. For 2003, PSCo is authorized to fully recover its retail electric fuel and purchased energy expense through the interim adjustment clause (IAC). In addition to the IAC, PSCo has other adjustment clauses that allow certain costs to be recovered from retail customers.

Xcel Energy has two distinct forms of electric wholesale sales: short-term wholesale and electric commodity trading. Short-term wholesale refers to electric sales for resale, which are associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Electric commodity trading refers to the sales for resale activity of purchasing and reselling electric energy to the wholesale market. Short-term wholesale and electric trading activities are considered part of the electric utility segment.

Xcel Energy’s electric commodity trading operations are conducted by NSP-Minnesota and PSCo. Margins from electric trading activity are partially redistributed to other operating utilities of Xcel Energy, pursuant to a joint operating agreement (JOA) approved by the Federal Energy Regulatory Commission (FERC). PSCo’s short-term wholesale and electric trading margins reflect the impact of regulatory sharing, if applicable, of certain margins with Colorado retail customers. Trading revenues, as discussed in Note 1 to the Consolidated Financial Statements, are reported net (i.e., on a margin basis) in the Consolidated Statements of Operations. Trading revenue and costs associated with NRG’s operations are included in discontinued operations. Xcel Energy has participated in natural gas commodity trading through e prime, which is now considered a discontinued operation for all periods presented. Consequently, neither NRG nor e prime trading activity is reflected in the following table. The following table details the revenue and margin for base electric utility, short-term wholesale and electric commodity trading activities:

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The following summarizes the components of the changes in base electric utility revenue and base electric utility margin for the years ended Dec. 31:

Base Electric Utility Revenue

2003 Comparison with 2002 — Base electric utility revenues increased due to weather-normalized retail sales growth of approximately 1.5 percent, higher fuel and purchased power costs, which are largely passed through to customers, and higher capacity sales in Texas. In addition, the AQIR was implemented in Colorado in January 2003 for the recovery of investments and related costs to improve air quality. Partially offsetting the higher revenues was the impact of warmer temperatures during the summer of 2002 compared with the summer of 2003, as well as 2003 rate reductions related to lower property taxes in Minnesota and estimated customer refunds related to service quality requirements in Colorado.

2002 Comparison with 2001 — Base electric utility revenues decreased due mainly to lower fuel and purchased power costs, which are largely passed through to customers, and lower capacity sales in Texas. In addition, 2002 revenues were lower due to the 2001 allowed recovery of 1998 incentives associated with state-mandated programs for energy conservation. The amounts were previously recorded as liabilities potentially due to Minnesota customers. Partially offsetting the decreases in revenue was weather-normalized retail sales growth of approximately 1.8 percent, the impact of warmer temperatures during the summer of 2002 compared with 2001 and lower 2002 estimated customer refunds related to both service quality requirements in Colorado and property tax refunds in Minnesota.

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Base Electric Utility Margin

2003 Comparison to 2002 — Base electric utility margin decreased due mainly to higher purchased capacity costs associated with new contracts to support growth, the allowed recovery of fuel and purchased power costs in excess of actual costs in 2002 under the sharing provisions of the incentive cost adjustment mechanism in Colorado, compared with passing through costs with no sharing provisions under the IAC in 2003 and the impact of weather. Also decreasing margin were 2003 rate reductions related to lower property taxes in Minnesota and estimated refunds to customers related to service quality requirements in Colorado. The decreases were partially offset by weather-normalized sales growth, the implementation of the AQIR and higher capacity sales, as previously discussed.

2002 Comparison to 2001 — Base electric utility margin increased due to weather-normalized retail sales growth, the impact of weather and lower 2002 estimated customer refunds related to both service quality requirements in Colorado and property tax refunds in Minnesota. In addition, the higher base electric margins in 2002 reflect lower unrecovered costs, due in part to resetting the base-energy-cost recovery at PSCo in January 2002. In 2001, PSCo’s allowed recovery was approximately $78 million less than its actual costs, while in 2002, its allowed recovery was approximately $29 million more than its actual costs. Partially offsetting the increased margin was the 2001 conservation incentive recovery discussed previously and higher purchased capacity costs due to new contracts to support growth and lower capacity sales in Texas.

Short-Term Wholesale and Electric Commodity Trading Margin

2003 Comparison to 2002 — Short-term wholesale and electric commodity trading margins increased approximately $43 million in 2003 compared with 2002. The increase reflects more favorable market conditions in the northern regions.

2002 Comparison to 2001 — Short-term wholesale and electric commodity trading sales margins decreased an aggregate of approximately $209 million in 2002, compared with 2001. The decrease in short-term wholesale and electric commodity trading margin reflects less favorable market conditions in the western regions.

Natural Gas Utility Margins

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

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The following summarizes the components of the changes in natural gas revenue and margin for the years ended Dec. 31:

Natural Gas Revenue

2003 Comparison to 2002 — Natural gas revenue increased mainly due to higher natural gas costs in 2003, which are passed through to customers.

2002 Comparison to 2001 — Natural gas revenue decreased mainly due to lower natural gas costs in 2002, which are passed through to customers.

Natural Gas Margin

2003 Comparison to 2002 — Natural gas margin decreased due to base rate decreases agreed to in the settlement of the PSCo 2002 general rate case and the impact of warmer winter temperatures in 2003 compared with 2002. The rate case settlement agreement is discussed further under Factors Affecting Results of Continuing Operations. Partially offsetting the rate decrease was weather-normalized sales growth of 1.6 percent.

2002 Comparison to 2001 — Natural gas margin increased due mainly to the impact of colder winter temperatures in 2002 compared with 2001.

Weather — Xcel Energy’s earnings can be significantly affected by weather. Unseasonably hot summers or cold winters increase electric and natural gas sales, but also can increase expenses. Unseasonably mild weather reduces electric and natural gas sales, but may not reduce expenses, which affects overall results. The impact of weather on earnings is based on the number of customers, temperature variances and the amount of gas or electricity the average customer historically has used per degree of temperature.

The following summarizes the estimated impact on the earnings of the utility subsidiaries of Xcel Energy due to temperature variations from historical averages:

•		weather in 2003 had minimal impact on earnings per share;
•		weather in 2002 increased earnings by an estimated 6 cents per share; and
•		weather in 2001 had minimal impact on earnings per share.

Nonregulated Operating Margins

The following table details the changes in nonregulated revenue and margin included in continuing operations:

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2003 Comparison to 2002 — Nonregulated revenue increased in 2003, due mainly to increasing customer levels in Seren’s communication business. Nonregulated margin decreased in 2003, due to higher cost of goods sold at a subsidiary of Utility Engineering offsetting the revenue increases at Seren.

2002 Comparison to 2001 — Nonregulated margin decreased in 2002 compared to 2001, due to higher cost of goods sold at a subsidiary of Utility Engineering.

Non-Fuel Operating Expense and Other Items

Other Utility Operating and Maintenance Expense — Other utility operating and maintenance expense for 2003 increased by approximately $91 million, or 6.1 percent, compared with 2002. The increase is due primarily to higher employee related costs, including higher performance-based compensation of $36 million, restricted stock unit grants of $29 million, lower pension credits of $19 million and higher medical and health care costs of $9 million. In 2002 there were no restricted stock unit grants and only a partial award of performance-based compensation. In addition, other utility operating and maintenance expense for 2003 reflects inventory write-downs of $8 million, higher uncollectible accounts receivable of $3 million, higher reliability expenses of $6 million and a software project write-off of $2 million. The increase was partially offset by lower information technology costs resulting from centralization.

Other utility operating and maintenance expense for 2002 decreased by approximately $3 million, or 0.2 percent, compared with 2001. The decreased costs reflect lower incentive compensation and other employee benefit costs of $20 million, as well as lower staffing levels in the corporate areas of approximately $11 million due to completion of the corporate merger synergy plans in late 2001. These decreases were substantially offset by higher costs associated with plant outages of $11 million due to planned outages at multiple plants and higher property insurance costs of $9 million due to unfavorable market conditions in 2002, in addition to inflationary factors such as market wage increases and general market inflation.

Other Nonregulated Operating and Maintenance Expense — Other nonregulated operating and maintenance expenses decreased $8 million, or 7.7 percent, in 2003 compared with 2002. Other nonregulated operating and maintenance expenses in 2002 increased $20 million, or 22.8 percent, compared with 2001. The 2002 expenses included employee severance costs at the holding company. These expenses are included in the results for each nonregulated subsidiary, as discussed later.

Depreciation and Amortization Expense — Depreciation and amortization expense decreased by approximately $15 million, or 2.0 percent, for 2003, compared with 2002. This decrease reflects the impacts of nuclear plant life extensions at Prairie Island and certain depreciation rate changes in Colorado, partially offset by increasing depreciation related to plant additions. The increase in depreciation and amortization in 2002 compared with 2001 is also due to the impacts of plant additions.

In December 2003, the Minnesota Public Utilities Commission (MPUC) extended the authorized useful lives of the two NSP-Minnesota generating units at the Prairie Island nuclear plant until 2013 and 2014, respectively. The recovery was effective Jan. 1, 2003, and the net effect on depreciation and amortization, partially offset by revisions to nuclear decommissioning accrual, was a $22 million decrease in depreciation expense. In addition, effective July 1, 2003, the Colorado Public Utilities Commission (CPUC) lengthened the depreciable lives of certain electric utility plant at PSCo as a part of the general Colorado rate case, which will reduce annual depreciation expense by $20 million and reduced 2003 depreciation expense by approximately $10 million.

Special Charges — Special charges reported in 2003 relate to the TRANSLink project and NRG restructuring costs. Special charges for 2002 include NRG restructuring costs, as discussed later, but are largely related to regulated utility costs as discussed in the following paragraph. All 2001 special charges relate to utility costs. See Note 2 to the Consolidated Financial Statements for further discussion of these items.

Regulated utility earnings from continuing operations were reduced by approximately 2 cents per share in 2002 due to a $5 million regulatory recovery adjustment for SPS and $9 million in employee separation costs associated with a restaffing initiative for utility and service company operations. Regulated utility earnings from continuing operations in 2001 were lower by 4 cents per share due to a Colorado Supreme Court decision that resulted in a pretax write-off of $23 million of a regulatory asset related to deferred post-employment benefit costs at PSCo. Also, regulated utility earnings from continuing operations were reduced by approximately 7 cents per share in 2001 due to $39 million of employee separation costs associated with a restaffing initiative late in the year for utility and service company operations.

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Interest and Other Income, Net of Nonoperating Expenses — Interest and other income, net of nonoperating expenses decreased $9 million in 2003 compared with 2002. Interest income decreased $13 million in 2003 compared with 2002 primarily due to interest received on tax refunds in 2002. Other income decreased $11 million primarily due to a gain on the sale of contracts at Planergy in 2002. Partially offsetting these decreases was an increase in allowance for funds used during construction resulting from lower levels of short-term debt used to finance utility construction.

Interest and other income, net of nonoperating expenses increased $14 million from 2002 compared with 2001. Interest income increased by $8 million primarily due to interest received on tax refunds in 2002. Other income increased by $13 million, primarily due to a gain on the sale of contracts at Planergy in 2002. Partially offsetting these increases was a decrease in the gain on disposal of assets of $5 million due to a gain recorded in 2001 by PSCo.

Interest and Financing Costs — Interest and financing costs increased approximately $30 million, or 7.1 percent, for 2003 compared with 2002. This increase was due to the full-year impact of the issuance of long-term debt in the latter part of 2002 intended to reduce dependence on short-term debt. In addition, during the fourth quarter of 2002, Xcel Energy incurred approximately $15 million to redeem temporary holding company debt. During 2003, Xcel Energy issued approximately $1.7 billion of long-term debt to refinance higher coupon debt. These actions are expected to reduce 2004 interest costs by approximately $15 million compared with 2003 levels.

Interest and financing costs increased $56 million, or 15.3 percent, in 2002 compared with 2001. During 2002, certain long-term debt was refinanced at higher interest rates. Additionally, certain redemption costs were incurred, as noted previously.

Income Tax Expense — Income tax expense decreased by approximately $77 million in 2003, compared with a decrease of $69 million in 2002. The effective tax rate for 2003 was 23.7 percent, compared with 30.9 percent in 2002. The decrease in the effective rate in 2003 was due largely to approximately $36 million of tax adjustments recorded mainly in the fourth quarter of 2003 to reflect the successful resolution of various outstanding tax issues related to prior years. The tax issues resolved during 2003 included the tax deductibility of certain merger costs associated with the merger to form Xcel Energy and NCE and the deductibility, for state purposes, of certain tax benefit transfer lease benefits. Tax expense also decreased in 2003 due to lower income levels in 2003. The decrease in 2002 was primarily due to increased tax credits and lower pretax income in 2002. See Note 10 to the Consolidated Financial Statements.

Other Nonregulated Subsidiaries and Holding Company Results

The following tables summarize the net income and earnings per share contributions of the continuing operations of Xcel Energy’s nonregulated businesses and holding company results:

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Eloigne Company — Eloigne invests in affordable housing that qualifies for Internal Revenue Service tax credits. Eloigne’s earnings contribution declined slightly in 2003 and 2002 as tax credits on mature affordable housing projects began to decline.

Seren Innovations — Seren operates a combination cable television, telephone and high-speed Internet access system in St. Cloud, Minn., and Contra Costa County, Calif. Operation of its broadband communications network has resulted in losses. Seren has completed its build-out phase and has been experiencing improvement in its operating results. Neutral cash flow is expected in 2004 and positive cash flow is projected for 2005. A positive earnings contribution is anticipated in 2007, assuming customer addition goals are met.

Planergy — Planergy provides energy management services. Planergy’s losses were lower in 2002 largely due to pretax gains of approximately $8 million from the sale of a portfolio of energy management contracts, which reduced losses by approximately 2 cents per share.

Financing Costs and Preferred Dividends — Nonregulated results include interest expense and the earnings-per-share impact of preferred dividends, which are incurred at the Xcel Energy and intermediate holding company levels, and are not directly assigned to individual subsidiaries.

In November 2002, the Xcel Energy holding company issued temporary financing, which included detachable options for the purchase of Xcel Energy notes, which are convertible to Xcel Energy common stock. This temporary financing was replaced with long-term holding company financing in late November 2002. Costs incurred to redeem the temporary financing included a redemption premium of $7.4 million, $5.2 million of debt discount associated with the detachable option, and other issuance costs, which increased financing costs and reduced 2002 earnings by 2 cents per share.

Financing costs and preferred dividends per share for 2003 included above reflect the impact of dilutive securities, as discussed further in Note 11 to the Consolidated Financial Statements. The impact of the dilutive securities, if converted, is a reduction of interest expense of approximately $11 million, or 3 cents per share.

Holding Company Special Charges — During 2002, NRG experienced credit-rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity. These events ultimately led to the restructuring of NRG in late 2002 and its bankruptcy filing in May 2003. See Note 4 to the Consolidated Financial Statements. Certain costs related to NRG’s restructuring were incurred at the holding company level and included in continuing operations and reported as Special Charges. Approximately $12 million of these costs were incurred in 2003 and $5 million were incurred in 2002, which reduced after-tax earnings by approximately 2 cents per share and 1 cent per share, respectively. Costs in 2003 included approximately $32 million of financial advisor fees, legal costs and consulting costs related to the NRG bankruptcy transaction. These charges were partially offset by a $20 million pension curtailment gain related to the termination of NRG employees from Xcel Energy’s pension plan. In 2003, Xcel Energy also recorded a $7 million charge in connection with the suspension of the formation of the independent transmission company TRANSLink Transmission Co., LLC (TRANSLink). See Note 2 to the Consolidated Financial Statements for further discussion of these special charges.

Other Nonregulated — In 2003, Utility Engineering sold water rights, resulting in a pretax gain (reported as nonoperating income) of $15 million. The gain increased after-tax income by approximately 2 cents per share.

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Statement of Operations Analysis — Discontinued Operations

A summary of the various components of discontinued operations is as follows for the years ended Dec. 31:

Regulated Natural Gas Utility Results — Discontinued Operations

During 2003, Xcel Energy completed the sale of two subsidiaries in its regulated natural gas utility segment: Viking, including its interest in Guardian Pipeline, LLC, and BMG. After-tax disposal gains of $23.3 million, or 6 cents per share, were recorded for the natural gas utility segment, primarily related to the sale of Viking.

Viking had minimal income in 2003, as it was sold in January of that year. Income from Viking was higher in 2002 compared with 2001 primarily due to increased revenues.

NRG Results — Discontinued Operations

Due to NRG’s emergence from bankruptcy in December 2003 and Xcel Energy’s corresponding divestiture of its ownership interest in NRG, Xcel Energy’s share of NRG results for current and prior periods is now shown as a component of discontinued operations.

2003 NRG Results Compared with 2002 — As a result of NRG’s bankruptcy filing in May 2003, Xcel Energy ceased the consolidation of NRG and began accounting for its investment in NRG using the equity method in accordance with Accounting Principles Board Opinion No. 18 — “The Equity Method of Accounting for Investments in Common Stock.” After changing to the equity method, Xcel Energy was limited in the amount of NRG’s losses subsequent to the bankruptcy date that it was required to record. In accordance with these limitations under the equity method, Xcel Energy stopped recognizing equity in the losses of NRG subsequent to the quarter ended June 30, 2003. These limitations provided for loss recognition by Xcel Energy until its investment in NRG was written off to zero, with further loss recognition to continue if its financial commitments to NRG exist beyond amounts already invested. Xcel Energy initially recorded more losses than the limitations allow as of June 30, 2003, but upon Xcel Energy’s divestiture of its interest in NRG, the NRG losses recorded in excess of Xcel Energy’s investment in and financial commitment to NRG were reversed in the fourth quarter of 2003. This resulted in a noncash gain of $111 million, or 26 cents per share, for the quarter and an adjustment of the total NRG losses recorded for the year 2003 to $251 million, or 60 cents per share.

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NRG’s results included in Xcel Energy’s earnings for 2003 were as follows:

*

These represent NRG losses incurred in the first and second quarters of 2003 that were in excess of the amounts recordable by Xcel Energy under the equity method of accounting limitations discussed previously.

Following its credit downgrade in July 2002, NRG experienced credit and liquidity constraints and commenced a financial and business restructuring, including a voluntary petition for bankruptcy protection. This restructuring created significant incremental costs and resulted in numerous asset impairments as the strategic and economic value of assets under development and in operation changed.

NRG’s asset impairments and related charges in 2003 include approximately $40 million in first-quarter charges related to NRG’s NEO landfill gas projects and equity investments, and approximately $500 million was recorded in the second quarter. The impairment and related charges in the second quarter of 2003 resulted from planned disposals of the Loy Yang project in Australia and the McClain and Brazos Valley projects in the United States, and regulatory developments and changing circumstances throughout the second quarter that adversely affected NRG’s ability to recover the carrying value of certain Connecticut merchant generation units. As of the bankruptcy filing date (May 14, 2003), Xcel Energy had recognized $263 million of NRG’s impairments and related charges for the Connecticut facilities and Brazos Valley as these charges were recorded by NRG prior to May 14, 2003. Consequently, Xcel Energy recorded its equity in NRG results for the second quarter (including these impairments) in excess of its financial commitment to NRG under the settlement agreement reached in March 2003 among Xcel Energy, NRG and NRG’s creditors. These excess losses were reversed upon NRG’s emergence from bankruptcy in December 2003, as discussed previously.

In 2003, NRG’s operating results (excluding the unusual items discussed above) were affected by higher market prices due to higher natural gas prices and an increase in capacity revenues due to additional projects becoming operational in the later part of 2002. In addition, the sale of an NRG investment in 2002 resulted in a favorable impact in 2003 as the investment generated substantial equity losses in the prior years. The increase was offset by losses incurred on contracts in Connecticut due to increased market prices, increased operating expenses, contract terminations and liquidated damages triggered by NRG’s financial condition and additional restructuring charges.

During 2002, the tax filing status of NRG for 2002 and future years changed from being included as part of Xcel Energy’s consolidated federal income tax group to filing on a stand-alone basis. On a stand-alone basis, NRG did not have the ability to recognize all tax benefits that may ultimately accrue from its 2003 operating losses and is currently in a net operating loss carry forward position for tax purposes. Accordingly, NRG’s results for 2003 include no material tax effects.

2002 NRG Results Compared with 2001 — NRG losses in 2002 were $3.4 billion, or $8.95 per share, due primarily to asset impairment charges and estimated disposal losses of more than $3 billion and other charges recorded in the third and fourth quarters of 2002 related to NRG’s financial restructuring. Also, NRG recorded other incremental costs related to its financial restructuring and business realignment.

During 2002, NRG’s operations, excluding impacts of asset impairments and disposals and restructuring costs, experienced significant losses compared with 2001. The 2002 losses are primarily attributable to NRG’s North American operations, which experienced significant reductions in domestic energy and capacity sales and an overall decrease in power pool prices and related spark spreads. In addition, increased administrative costs, depreciation and interest expense from completed construction contributed to the less-than-favorable results for NRG in 2002.

As discussed previously, on a stand-alone basis, NRG did not have the ability to recognize all tax benefits that may ultimately accrue from its losses incurred in 2002, thus increasing the overall loss from continuing operations. In addition to losing the ability to recognize all tax benefits for operating losses, NRG in 2002 also lost the ability to utilize tax credits generated by its energy projects. These lower tax credits account for a portion of the decreased earnings contribution of NRG compared with results in 2001, which included income related to recognition of tax credits.

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See Notes 3 and 4 to the Consolidated Financial Statements for further discussion of the 2003 change in accounting for NRG, Xcel Energy’s limitation for recognizing NRG’s losses due to its bankruptcy filing and further discussion of NRG’s results included in discontinued operations, including asset impairment charges.

Other Nonregulated Results — Discontinued Operations

During 2003, the board of directors of Xcel Energy approved management’s plan to exit the businesses conducted by its nonregulated subsidiaries, Xcel Energy International and e prime. Xcel Energy is in the process of marketing the assets and operations of these businesses to prospective buyers and expects to exit the businesses during 2004.

2003 Nonregulated Results Compared with 2002 — Results of discontinued nonregulated operations, other than NRG, include an after-tax loss of $59 million, or 14 cents per share, expected on the disposal of Xcel Energy International’s assets, based on the estimated fair value of such assets. Xcel Energy’s remaining investment in Xcel Energy International at Dec. 31, 2003, was approximately $39 million. These losses from discontinued nonregulated operations also include a charge of $16 million for costs of settling a Commodity Futures Trading Commission trading investigation of e prime.

2002 Nonregulated Results Compared with 2001 — Nonregulated and holding company earnings for 2002 were reduced by impairment losses recorded by Xcel Energy International for Argentina assets and disposal losses for Yorkshire Power. In 2002, Xcel Energy International decided it would no longer fund one of its power projects in Argentina. This decision resulted in the shutdown of the Argentina plant facility, pending financing of a necessary maintenance outage. Updated cash flow projections for the plant were insufficient to provide recovery of Xcel Energy International’s investment. The write-down for this Argentina facility was approximately $13 million, or 3 cents per share.

In August 2002, Xcel Energy announced it had sold Xcel Energy International’s 5.25-percent interest in Yorkshire Power Group Limited for $33 million to CE Electric UK. Xcel Energy International and American Electric Power Co. each held a 50-percent interest in Yorkshire, a UK retail electricity and natural gas supplier and electricity distributor, before selling 94.75 percent of Yorkshire to Innogy Holdings plc in April 2001. The sale of the 5.25-percent interest resulted in an after-tax loss of $8.3 million, or 2 cents per share, in the third quarter of 2002.

Tax Benefits Related to Investment in NRG — With NRG’s emergence from bankruptcy in December 2003, Xcel Energy has divested its ownership interest in NRG and plans to take a loss deduction in 2003. These benefits, since related to Xcel Energy’s investment in discontinued NRG operations, are also reported as discontinued operations. During 2002, Xcel Energy recognized an initial estimate of the expected tax benefits of $706 million. This benefit was based on the estimated tax basis of Xcel Energy’s cash and stock investments already made in NRG, and their deductibility for federal income tax purposes.

Based on the results of a 2003 study, Xcel Energy recorded $105 million of additional tax benefits in the third quarter of 2003, reflecting an updated estimate of the tax basis of Xcel Energy’s investments in NRG and state tax deductibility. Upon NRG’s emergence from bankruptcy, an additional $288 million of tax benefit was recorded in the fourth quarter of 2003 to reflect the deductibility of expected settlement payments of $752 million, uncollectible receivables from NRG, other state tax benefits and further adjustments to the estimated tax basis in NRG. Another $11 million of state tax benefits were accrued earlier in 2003 based on projected impacts.

Based on current forecasts of taxable income and tax liabilities, Xcel Energy expects to realize approximately $1.1 billion of cash savings from these tax benefits through a refund of taxes paid in prior years and reduced taxes payable in future years. Xcel Energy used $130 million of these tax benefits in 2003 and expects to use $480 million in 2004. The remainder of the tax benefit carry forward is expected to be used over subsequent years.

Extraordinary Item — Electric Utility Restructuring

In 2001, SPS recorded extraordinary income of $18 million before tax, or 3 cents per share, related to the regulated utility business to reflect the impacts of industry restructuring developments for SPS. This represented a reversal of a portion of an extraordinary loss recorded in 2000 related to industry restructuring. For more information on this 2001 extraordinary item, see Note 14 to the Consolidated Financial Statements.

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Factors Affecting Results of Continuing 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 natural gas service within their respective jurisdictions and affect our ability to recover our costs from customers. In addition, Xcel Energy’s nonregulated businesses have had an adverse impact on Xcel Energy’s earnings in 2003 and 2002. The historical and future trends of Xcel Energy’s operating results have been, and are expected to be, affected by a number of factors, including the following:

General Economic Conditions

Economic conditions may have a material impact on Xcel Energy’s operating results. The United States economy is showing recent signs of recovery as measured by growth in the gross domestic product. However, certain operating costs, such as insurance and security, have increased due to economic uncertainty, terrorist activity and war or the threat of war. Management cannot predict the impact of a future economic slowdown, fluctuating energy prices, war or the threat of war. However, Xcel Energy could experience a material adverse impact to its results of operations, future growth or ability to raise capital from a stalled economic recovery.

Sales Growth

In addition to the impact of weather, customer sales levels in Xcel Energy’s regulated utility businesses can vary with economic conditions, customer usage patterns and other factors. Weather-normalized sales growth for retail electric utility customers was estimated to be 1.5 percent in 2003 compared with 2002, and 1.8 percent in 2002 compared with 2001. Weather-normalized sales growth for firm gas utility customers was estimated to be approximately 1.6 percent in 2003 compared with 2002, and relatively flat in 2002 compared with 2001. Projections indicate that weather-normalized sales growth in 2004 compared with 2003 will be approximately 2.2 percent for retail electric utility customers and 2.4 percent for firm gas utility customers.

Utility Industry Changes

The structure of the electric and natural gas utility industry has been subject to change. Merger and acquisition activity in the past has been significant as utilities combined to capture economies of scale or establish a strategic niche in preparing for the future, although such activity slowed substantially after 2001. All utilities were required to provide nondiscriminatory access to the use of their transmission systems in 1996. In addition, the FERC issued a series of regulatory orders in 2003. These orders, among other things, standardized the methods and pricing of power generation interconnections, established new standards of conduct rules for transmission providers and new code of conduct rules for utilities with market-based rate authority. Xcel Energy has not yet estimated the full impact of the new FERC regulatory orders, but it could be material.

Some states had begun to allow retail customers to choose their electricity supplier, while other states have delayed or canceled industry restructuring. There were no significant retail electric or natural gas restructuring efforts in the states served by Xcel Energy in 2003.

Xcel Energy cannot predict the outcome of restructuring proceedings in the electric utility jurisdictions it serves at this time. The resolution of these matters may have a significant impact on the financial position, results of operations and cash flows of Xcel Energy.

Pension Plan Costs and Assumptions

Xcel Energy’s pension costs are based on an actuarial calculation that includes a number of key assumptions, most notably the annual return level that pension investment assets will earn in the future and the interest rate used to discount future pension benefit payments to a present value obligation for financial reporting. In addition, the actuarial calculation uses an asset-smoothing methodology to reduce the volatility of varying investment performance over time. Note 12 to the Consolidated Financial Statements discusses the rate of return and discount rate used in the calculation of pension costs and obligations in the accompanying financial statements.

Pension costs have been increasing in recent years, and are expected to increase further over the next several years, due to lower-than-expected investment returns experienced in 2000, 2001 and 2002 and decreases in interest rates used to discount benefit obligations. While investment returns exceeded the assumed level of 9.25 percent in 2003, investment returns in 2001 and 2002 were below the assumed level of 9.5 percent and discount rates have declined from the 7.25-percent to 8-percent levels used in 1999 through 2002 cost determinations to 6.75 percent used in 2003. Xcel Energy continually reviews its pension assumptions and, in 2004, expects to change the investment return assumption to 9.0 percent and the discount rate assumption to 6.25 percent.

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The investment gains or losses resulting from the difference between the expected pension returns assumed on smoothed or “market-related” asset levels and actual returns earned is deferred in the year the difference arises and recognized over the subsequent five-year period. This gain or loss recognition occurs by using a five-year, moving-average value of pension assets to measure expected asset returns in the cost determination process, and by amortizing deferred investment gains or losses over the subsequent five-year period. Based on the use of average market-related asset values, and considering the expected recognition of past investment gains and losses over the next five years, achieving the assumed rate of asset return of 9.0 percent in each future year and holding other assumptions constant, Xcel Energy currently projects that the pension costs recognized for financial reporting purposes in continuing operations will increase from a credit, or negative expense, of $51 million in 2003 to a credit of $25 million in 2004 and zero in 2005. Pension costs are currently a credit due to the recognized investment asset returns exceeding the other pension cost components, such as benefits earned for current service and interest costs for the effects of the passage of time on discounted obligations.

Xcel Energy bases its discount rate assumption on benchmark interest rates quoted by an established credit rating agency, Moody’s Investors Service (Moody’s), and has consistently benchmarked the interest rate used to derive the discount rate to the movements in the long-term corporate bond indices for bonds rated Aaa through Baa by Moody’s, which have a period to maturity comparable to our projected benefit obligations. At Dec. 31, 2003, the annualized Moody’s Aa index rate, roughly in the middle of the Aaa and Baa range, declined by about 0.5 percent from the prior year end, which resulted in a corresponding decrease from 6.75 percent at year-end 2002 to a 6.25-percent pension discount rate at year-end 2003. This rate was used to value the actuarial benefit obligations at that date, and will be used in 2004 pension cost determinations.

If Xcel Energy were to use alternative assumptions for pension cost determinations, a 1-percent change would result in the following impacts on the estimated pension costs recognized by Xcel Energy for financial reporting purposes:

•		a 100 basis point higher rate of return, 10.0 percent, would decrease 2004 pension costs by $18.4 million;
•		a 100 basis point lower rate of return, 8.0 percent, would increase 2004 pension costs by $18.4 million;
•		a 100 basis point higher discount rate, 7.25 percent, would decrease 2004 pension costs by $9.5 million; and
•		a 100 basis point lower discount rate, 5.25 percent, would increase 2004 pension costs by $8.8 million.

Alternative Employee Retirement Income Security Act of 1974 (ERISA) funding assumptions would also change the expected future cash funding requirements for the pension plans. Cash funding requirements can be affected by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding in recent years for Xcel Energy’s pension plans, and do not require funding in 2004. Assuming that future asset return levels equal the actuarial assumption of 9.0 percent for the years 2004 and 2005, Xcel Energy projects, under current funding regulations, that cash funding would be required in the amount of approximately $0 million for 2005 and $15 million for 2006. Actual performance can affect these funding requirements significantly. Current funding regulations were under legislative review in 2004 and, if not retained in their current form, could change these funding requirements materially. To begin meeting these projected funding requirements, PSCo elected to make a voluntary contribution of $30 million to its pension plan for bargaining employees in 2003, and it plans to voluntarily contribute another $10 million to the plan in 2004.

Regulation

Xcel Energy, its utility subsidiaries and certain of its nonutility subsidiaries are subject to extensive regulation by the SEC under the PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties and intra-system sales of certain goods and services. In addition, the PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. See further discussion of financing restrictions under Liquidity and Capital Resources.

Xcel Energy’s utility subsidiaries also are regulated by the FERC and state regulatory commissions. Decisions by these regulators can significantly impact Xcel Energy’s results of operations. Xcel Energy expects to periodically file for rate changes based on changing energy market and general economic conditions.

The electric and natural gas rates charged to customers of Xcel Energy’s utility subsidiaries are approved by the FERC and the regulatory commissions in the states 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.

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Most of the retail rates for Xcel Energy’s utility subsidiaries provide for periodic adjustments to billings and revenues to allow for recovery of changes in the cost of fuel for electric generation, purchased energy, purchased natural gas and, in Minnesota and Colorado, conservation and energy-management program costs. In Minnesota and Colorado, changes in purchased electric capacity costs are not recovered through these rate-adjustment mechanisms. For Wisconsin electric operations, where automatic cost-of-energy adjustment clauses are not allowed, the biennial retail rate review process and an interim fuel-cost hearing process provide the opportunity for rate recovery of changes in electric fuel and purchased energy costs in lieu of a cost-of-energy adjustment clause. In Colorado, PSCo has an interim adjustment clause that allows for recovery of all prudently incurred electric fuel and purchased energy expenses in 2003. In 2004, PSCo generally is expected to recover all prudently incurred electric fuel and purchased energy costs through an electric commodity adjustment clause. Additionally, this fuel mechanism also has in place a sharing among customers and shareholders of certain fuel and energy costs, with an $11.25 million maximum on any cost sharing over or under an allowed electric commodity adjustment formula rate, and a sharing among shareholders and customers of certain gains and losses on trading margins.

Xcel Energy’s utility subsidiaries make substantial investments in plant additions to build and upgrade power plants, and expand and maintain the reliability of the energy distribution system. In addition to filing for increases in base rates charged to customers to recover the costs associated with such investments, in 2003 approval was obtained from Colorado and Minnesota regulators to recover, through a rate surcharge, certain costs to upgrade plants and lower emissions in the Denver and Minneapolis-St. Paul metropolitan areas. These rate recovery mechanisms are expected to provide significant cash flows to enable recovery of costs incurred on a timely basis.

Regulated public utilities are allowed to record as regulatory assets certain costs that are expected to be recovered from customers in future periods and to record as regulatory liabilities certain income items that are expected to be refunded to customers in future periods. In contrast, nonregulated enterprises would expense these costs and recognize the income in the current period. 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 effect on Xcel Energy’s results of operations in the period the write-off is recorded.

At Dec. 31, 2003, Xcel Energy reported on its balance sheet regulatory assets of approximately $572 million and regulatory liabilities of approximately $1.2 billion that would be recognized in the statement of operations 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. See Notes 1 and 19 to the Consolidated Financial Statements for further discussion of regulatory deferrals.

PSCo 2002 General Rate Case — In May 2002, PSCo filed a combined general retail electric, natural gas and thermal energy base rate case with the CPUC as required in the merger approval agreement with the CPUC to form Xcel Energy. On April 4, 2003, a comprehensive settlement agreement was reached, which addressed all significant issues in the rate case. In mid-2003, the CPUC approved the final settlement, which provided for:

	•		a decrease in annual base rates of approximately $33 million for natural gas and $230,000 for electricity, including an annual reduction to electric depreciation expense of approximately $20 million, effective July 1, 2003;
	•		an interim adjustment clause (IAC) that fully recovers prudently incurred 2003 electric fuel and purchased energy expense above the expense recovered through electric base rates during 2003;
	•		a new electric commodity adjustment clause (ECA) for 2004-2006, with an $11.25-million cap on any cost sharing over or under an allowed ECA formula rate; and
	•		an authorized return on equity of 10.75 percent for electric operations and 11.0 percent for natural gas and thermal energy operations.

PSCo Performance-Based Regulatory Plan (PBRP) — The CPUC established an electric PBRP under which PSCo operates. The major components of this regulatory plan include:

•

an annual electric earnings test with the sharing between customers and shareholders of earnings in excess of the following limits:

	•		all earnings above an 11-percent return on equity for 2001 and a 10.50-percent return on equity for 2002;
	•		no earnings sharing for 2003 as PSCo established new rates in its general rate case; and
	•		an annual electric earnings test with the sharing of earnings in excess of the return on equity for electric operations of 10.75 percent for 2004 through 2006;

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•		an electric quality of service plan (QSP) that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to electric reliability and customer service through 2006; and
•		a natural gas QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to natural gas leak repair time and customer service through 2007.

PSCo regularly monitors and records as necessary an estimated customer refund obligation under the PBRP. 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.

	•		In 2001, PSCo did not earn a return on equity in excess of 11 percent and met the electric and gas QSP benchmarks. The CPUC has accepted the QSP components of the PBRP filing and approved the earnings test.
	•		In 2002, PSCo did not earn a return on equity in excess of 10.5 percent, so no refund liability has been recorded. Both electric and gas QSP benchmarks were met. Therefore, no liability has been recorded for the earnings test. A CPUC decision is pending. The CPUC is considering whether PSCo’s cost of debt has been adversely affected by the financial difficulties of NRG, and if so, whether any adjustments to PSCo’s cost of capital should be made. A hearing has been set for August 2004.
	•		The 2003 QSP results will be filed in April 2004. An estimate of customer refund obligations under the electric QSP plan was recorded in 2003 relating to the electric service unavailability and customer complaint measures. No refund under the gas QSP is anticipated.

In 2003, PSCo filed an application to put into effect a purchased-capacity cost-adjustment mechanism that would allow it to recover 100 percent of its incremental purchased-capacity costs over the level of these costs in rates. As a part of this application, PSCo proposed to modify the PBRP for 2004 through 2006 to provide that 100 percent of any earnings in excess of a 10.75-percent return on equity for electric operations be returned to customers. The application is pending approval of the CPUC.

Tax Matters

The Internal Revenue Service (IRS) issued a notice of proposed adjustment proposing to disallow interest expense deductions taken in tax years 1993 through 1997 related to corporate-owned life insurance (COLI) policy loans of PSR Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo. Late in 2001, Xcel Energy received a technical advice memorandum from the IRS national office, which communicated a position adverse to PSRI. Consequently, the IRS examination division has disallowed the interest expense deductions for the tax years 1993 through 1997. Xcel Energy plans to challenge the IRS determination, which could require several years to reach final resolution. Because it is Xcel Energy’s position that the IRS determination is not supported by tax law, Xcel Energy has not recorded any provision for income tax or interest expense related to this matter and continues to take deductions for interest expense related to policy loans on its income tax returns for subsequent years. However, defense of PSCo’s position may require significant cash outlays on a temporary basis if refund litigation is pursued in United States District Court.

The total disallowance of interest expense deductions for the period 1993 through 1997 is approximately $175 million. Additional interest expense deductions for the period 1998 through 2003 are estimated to total approximately $404 million. Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2003, would reduce earnings by an estimated $254 million, after tax. If COLI interest expense deductions were no longer available, annual earnings for 2004 would be reduced by an estimated $36 million, after tax, prospectively, which represents 9 cents per share using 2003 share levels.

Environmental Matters

Environmental costs include payments for 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 to the environment. A trend of greater environmental awareness and increasingly stringent regulation has caused, and may continue to cause, slightly higher operating expenses and capital expenditures for environmental compliance.

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

•		$133 million in 2003;
•		$138 million in 2002; and
•		$130 million in 2001.

Xcel Energy expects to expense an average of approximately $155 million per year from 2004 through 2008 for similar costs. However, the precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are currently unknown. Additionally, the extent to which environmental costs will be included in and recovered through rates is not certain.

Capital expenditures on environmental improvements at regulated facilities were approximately:

•		$58.5 million in 2003;
•		$107.8 million in 2002; and
•		$135.7 million in 2001.

The regulated utilities expect to incur approximately $83.0 million in capital expenditures for compliance with environmental regulations in 2004 and approximately $1.1 billion for environmental improvements during the period from 2004 through 2008. Approximately $43 million and $988 million of these expenditures, respectively, are related to modifications to reduce the emissions of NSP-Minnesota’s generating plants located in the Minneapolis-St. Paul metropolitan area pursuant to the metropolitan emissions reduction project (MERP), which are recoverable from customers through cost recovery mechanisms. See Notes 17 and 18 to the Consolidated Financial Statements for further discussion of our environmental contingencies.

Impact of Nonregulated Investments

Xcel Energy’s investments in nonregulated operations have had a significant impact on its results of operations. As a result of the divestiture of NRG, Xcel Energy does not expect that its investments in nonregulated operations will continue to have such a significant impact on its results. Xcel Energy does not expect to make any material investments in nonregulated projects. Xcel Energy’s remaining nonregulated businesses may carry a higher level of risk than its traditional utility businesses.

Xcel Energy’s earnings from nonregulated subsidiaries include investments in broadband communications systems through Seren. Management currently intends to hold and operate the Seren broadband communications system investments. As of Dec. 31, 2003, Xcel Energy’s investment in Seren was approximately $265 million. Seren had capitalized $331 million for plant in service and had incurred another $10 million for construction work in progress for these systems at Dec. 31, 2003.

Xcel Energy has also invested in international projects, primarily in Argentina, through Xcel Energy International, but has designated Xcel Energy International as held for sale as of Dec. 31, 2003. An estimated after-tax loss from disposal of Xcel Argentina assets of $59 million has been recorded, but may change as the final impacts of the divestiture become known in 2004.

Inflation

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

Critical Accounting Policies and Estimates

Preparation of the Consolidated Financial Statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the Consolidated Financial Statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the Consolidated

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Financial Statements and related disclosures, even if the nature of the accounting policies applied have not changed. The following is a list of accounting policies that are most significant to the portrayal of Xcel Energy’s financial condition and results, and that require management’s most difficult, subjective or complex judgments. Each of these has a higher potential likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been discussed with the audit committee of the Xcel Energy board of directors. Xcel Energy no longer considers NRG’s financial restructuring a critical accounting policy due to the divestiture resulting from NRG’s emergence from bankruptcy.

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Xcel Energy continually makes informed judgments and estimates related to these critical accounting policy areas, based on an evaluation of the varying assumptions and uncertainties for each area. For example:

	•		probable outcomes of regulatory proceedings are assessed in cases of requested cost recovery or other approvals from regulators;
	•		the ability to operate plant facilities and recover the related costs over their useful operating lives, or such other period designated by our regulators, is assumed;
	•		probable outcomes of reviews and challenges raised by tax authorities, including appeals and litigation where necessary, are assessed;
	•		returns are projected regarding earnings on pension investments, and the salary increases provided to employees over their periods of service; and
	•		future cash inflows of operations are projected in order to assess whether they will be sufficient to recover future cash outflows, including the impacts of product price changes and market penetration to customer groups.

The information and assumptions underlying many of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect the events and updated information that becomes available. The accompanying financial statements reflect management’s best estimates and judgments of the impacts of these factors as of Dec. 31, 2003.

Recently Implemented Accounting Changes

For a discussion of accounting changes implemented in 2003 and other significant accounting policies, see Notes 1, 16 and 18 to the Consolidated Financial Statements.

Pending Accounting Changes

FASB Interpretation No. 46 (FIN No. 46) — In January 2003, the Financial Accounting Standards Board (FASB) issued FIN No. 46, requiring an enterprise’s consolidated financial statements to include subsidiaries in which the enterprise has a controlling financial interest. Historically, consolidation has been required only for subsidiaries in which an enterprise has a majority voting interest. Under FIN No. 46, an enterprise’s consolidated financial statements will include the consolidation of variable interest entities, which are entities in which the enterprise has a controlling financial interest. As a result, Xcel Energy expects that it will be required to consolidate all or a portion of its affordable housing investments made through Eloigne, which currently are accounted for under the equity method. The Xcel Energy utility subsidiaries are party to purchased power agreements, and based on the current guidance, these contracts are not expected to be considered variable interest arrangements under the provisions of FIN No. 46. However, Xcel Energy is still evaluating the issue. Additionally, Xcel Energy is evaluating other arrangements based on criteria in FIN No. 46, and it is likely that some arrangements will require consolidation.

As of Dec. 31, 2003, the assets of the affordable housing investments were approximately $142 million and long-term liabilities were approximately $78 million. Currently, investments of $56 million are reflected as a component of investments in unconsolidated affiliates in the Dec. 31, 2003, Consolidated Balance Sheet. FIN No. 46 requires that for entities to be consolidated, the entities’ assets be initially recorded at their carrying amounts at the date the new requirement first applies. If determining carrying amounts as required is impractical, the assets are to be measured at fair value as of the first date the new requirements apply. Any difference between the net consolidated amounts added to Xcel Energy’s balance sheet and the amount of any previously recognized interest in the newly consolidated entity should be recognized in earnings as the cumulative-effect adjustment of an accounting change. Xcel Energy plans to adopt FIN No. 46 in the first quarter of 2004. The impact of consolidating these entities is not expected to have a material impact on net income.

DERIVATIVES, RISK MANAGEMENT AND MARKET RISK

Business and Operational Risk — Xcel Energy and its subsidiaries, including discontinued operations held for sale, are exposed to commodity price risk in their generation, retail distribution and energy trading operations. In certain jurisdictions, purchased energy expenses and natural gas costs are recovered on a dollar-for-dollar basis. However, in other jurisdictions, Xcel Energy and its subsidiaries are exposed to market price risk for the purchase and sale of electric energy and natural gas. In such jurisdictions, electric energy and natural gas expenses are recovered based on fixed-price limits or under established sharing mechanisms.

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Xcel Energy manages commodity price risk by entering into purchase and sales commitments for electric power and natural gas, long-term contracts for coal supplies and fuel oil, and derivative instruments. Xcel Energy’s risk management policy allows the company to manage the market price risk within each rate-regulated operation to the extent such exposure exists. Management is limited under the policy to enter into only transactions that manage market price risk where the rate regulation jurisdiction does not already provide for dollar-for-dollar recovery. One exception to this policy exists in which Xcel Energy uses various physical contracts and derivative instruments to reduce the volatility in the cost of natural gas and electricity provided to retail customers even though the regulatory jurisdiction may provide dollar-for-dollar recovery of actual costs. In these instances, the use of derivative instruments and physical contracts is done consistently with the local jurisdictional cost-recovery mechanism.

Xcel Energy and its subsidiaries have been exposed to market price risk for the sale of electric energy and the purchase of fuel resources, including coal, natural gas and fuel oil used to generate the electric energy within its nonregulated operations, primarily through NRG and Xcel Energy International. With the divestiture of NRG and expected sale of Xcel Energy International, the exposure to market price risk has greatly diminished. Xcel Energy managed this market price risk by entering into firm power sales agreements for approximately 55 percent to 75 percent of its electric capacity and energy from each generation facility, using contracts with terms ranging from one to 25 years. In addition, Xcel Energy managed the market price risk covering the fuel resource requirements to provide the electric energy by entering into purchase commitments and derivative instruments for coal, natural gas and fuel oil as needed to meet fixed-priced electric energy requirements. Xcel Energy’s risk management policy allows for the management of market price risks, and provides guidelines for the level of price risk exposure that is acceptable within the company’s operations.

Interest Rate Risk — Xcel Energy and its subsidiaries are subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy’s policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.

Xcel Energy engages in hedges of cash flow exposure and hedges of fair value exposure. The fair value of interest rate swaps designated as cash flow hedges are initially recorded in Other Comprehensive Income. Reclassification of unrealized gains or losses on cash flow hedges of variable rate debt instruments from Other Comprehensive Income into earnings occurs as interest payments are accrued on the debt instrument and generally offsets the change in the interest accrued on the underlying variable rate debt. Hedges of fair value exposure are entered into to hedge the fair value of a recognized asset, liability or firm commitment. Changes in the derivative fair values that are designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of related hedged assets, liabilities or firm commitments. In order to test the effectiveness of such swaps, a hypothetical swap is used to mirror all the critical terms of the underlying debt and regression analysis is utilized to assess the effectiveness of the actual swap at inception and on an ongoing basis. The assessment is done periodically to ensure the swaps continue to be effective. The fair value of interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.

At Dec. 31, 2003 and 2002, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable debt would impact net income by approximately $0.8 million and $12.6 million, respectively. See Note 15 to the Consolidated Financial Statements for a discussion of Xcel Energy and its subsidiaries’ interest rate swaps.

Currency Exchange Risk — During 2003 and 2002, NRG and Xcel Energy International, both of which are included in discontinued operations, held certain investments in foreign countries, creating exposure to foreign currency exchange risk. The foreign currency exchange risk included the risk relative to the recovery of the net investment in a project, as well as the risk relative to the earnings and cash flows generated from such operations. These subsidiaries managed their exposure to changes in foreign currency by entering into derivative instruments as determined by management. Xcel Energy’s risk management policy provides for this risk management activity.

Trading Risk — Xcel Energy’s subsidiaries conduct various trading operations and power marketing activities, including the purchase and sale of electric capacity and energy and, prior to December 2003, through e prime for natural gas. The trading operations are conducted in the United States with primary focus on specific market regions where trading knowledge and experience have been obtained. Xcel Energy’s risk management policy allows management to conduct the trading activity within approved guidelines and limitations as approved by the company’s risk management committee, which is made up of management personnel not involved in the trading operations.

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The fair value of the energy trading contracts of continuing operations as of Dec. 31, 2003 was as follows:

As of Dec. 31, 2003, the sources of fair value of the energy trading and hedging net assets were as follows:

Trading Contracts

Discontinued operations trading contracts are not included in the above table. The fair value of these contracts is approximately $(2.0) million, as of Dec. 31, 2003. All of these contracts have maturities of less than one year.

Hedge Contracts

Discontinued operations hedging contracts are not included in the above table. As of Dec. 31, 2003, the fair value of these contracts is approximately $1.5 million. All of these contracts have maturities of less than one year.

1 — Prices actively quoted or based on actively quoted prices.

2 — Prices based on models and other valuation methods. These represent the fair value of positions calculated using internal models when directly and indirectly quoted external prices or prices derived from external sources are not available. Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms. The models reflect management’s estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of energy commodity prices and contractual volumes. Market price uncertainty and other risks also are factored into the model.

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In the above tables, only hedge transactions are included for NSP-Minnesota, NSP-Wisconsin and PSCo. Normal purchases and sales transactions, as defined by SFAS No. 133, have been excluded.

At Dec. 31, 2003, a 10-percent fluctuation in market prices over the next 12 months for trading contracts would impact pretax income from continuing operations by approximately $1 million. Hedge contracts are accounted for as a component of Other Comprehensive Income and would not directly impact earnings.

Xcel Energy’s trading operations and power marketing activities measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value-at-Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time, with a given confidence interval under normal market conditions. Xcel Energy utilizes the variance/covariance approach in calculating VaR. The VaR model employs a 95-percent confidence interval level based on historical price movement, lognormal price distribution assumption, delta half-gamma approach for non-linear instruments and various holding periods varying from two to five days.

As of Dec. 31, 2003, the calculated VaRs were:

	(a)		Comprises transactions for both NSP-Minnesota and PSCo.
	(b)		Conducted by e prime, which is a discontinued operation held for sale.

     As of Dec. 31, 2002, the calculated VaRs were:

(a)		Comprises transactions for both NSP-Minnesota and PSCo.
(b)		NRG VaR was an undiversified VaR. NRG is presented as discontinued operations.
(c)		Conducted by e prime, which is a discontinued operation held for sale.

Credit Risk — In addition to the risks discussed previously, Xcel Energy and its subsidiaries are exposed to credit risk in the company’s risk management activities. Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations. Xcel Energy and its subsidiaries maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.

Xcel Energy and its subsidiaries conduct standard credit reviews for all counterparties. Xcel Energy employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions 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.

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At Dec. 31, 2003, a 10 percent increase in prices would have resulted in a net mark-to-market increase in credit risk exposure of $3.6 million, while a decrease of 10 percent would have resulted in a decrease of $3.9 million.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Cash provided by operating activities for continuing operations decreased during 2003 compared with 2002 primarily due to decreases in recovery of deferred fuel costs. Cash provided by operating activities for discontinued operations decreased during 2003 compared with 2002 due to the deconsolidation of NRG for 2003 reporting and the exclusion of any of its cash flows in that year. The decrease was partially offset by tax benefits received in connection with the divestiture of NRG in 2003.

Cash provided by operating activities for continuing operations decreased during 2002 compared with 2001 due to lower 2002 utility receivables and unbilled revenues, reflecting collections of higher year-end 2001 amounts. Cash provided by operating activities for discontinued operations increased during 2002 compared with 2001 primarily due to NRG’s efforts to conserve cash by deferring the payment of interest payments and managing its cash flows more closely. NRG’s accrued interest costs rose by nearly $200 million in 2002 compared with year-end 2001 levels.

Cash used in investing activities for continuing operations was approximately the same during 2003 compared with 2002 due to comparable utility construction expenditures. Cash flows for investing activities related to discontinued operations increased during 2003 compared with 2002 due to the deconsolidation of NRG for 2003 reporting and the exclusion of any of its cash flows in that year. NRG had significant construction expenditures during 2002 prior to its financial difficulties.

Cash used in investing activities for continuing operations decreased slightly during 2002 compared with 2001 primarily due to lower utility construction expenditures in 2002. Cash used in investing activities for discontinued operations decreased during 2002 compared with 2001 primarily due to lower levels of nonregulated capital expenditures as a result of NRG terminating its acquisition program due to its financial difficulties. Such nonregulated expenditures decreased $2.8 billion in 2002 due mainly to NRG asset acquisitions in 2001 that did not recur in 2002.

Cash flows for financing activities related to continuing operations decreased during 2003 compared with 2002 due to refinancing activities in 2003 to better align Xcel Energy’s capital structure and manage the cost of capital given the improving credit quality of Xcel Energy and its subsidiaries. During 2003, Xcel Energy and its subsidiaries extinguished $1.3 billion of long-term debt and issued approximately $1.7 billion of long-term debt, as shown in the Consolidated Statement of Capitalization. Cash flows for financing activities related to discontinued operations decreased during 2003 compared with 2002 due to the deconsolidation of NRG for 2003 reporting and the exclusion of any of its cash flows in that year. NRG obtained financing in 2002 for its construction expenditures prior to experiencing its financial difficulties.

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Cash flow for financing activities related to continuing operations increased during 2002 compared with 2001 primarily due to refinancing activities in 2002, including the redemption of $867 million of short-term debt and the issuance of $1.4 billion of new debt. Cash flow provided by financing activities for discontinued operations decreased during 2002 compared with 2001 primarily due to lower NRG capital requirements and constraints on NRG’s ability to access the capital market due to its financial difficulties, as discussed previously. NRG’s cash provided from financing activities declined by $2.7 billion in 2002 compared with 2001.

See discussion of trends, commitments and uncertainties with the potential for future impact on cash flow and liquidity under Capital Sources.

Capital Requirements

Utility Capital Expenditures, Nonregulated Investments and Long-Term Debt Obligations — The estimated cost of the capital expenditure programs of Xcel Energy and its subsidiaries, excluding discontinued operations, and other capital requirements for the years 2004, 2005 and 2006 are shown in the table below.

The capital expenditure forecast includes new steam generators at the Prairie Island nuclear plant, new combustion turbines in two NSP-Minnesota plants and costs related to a proposed coal-fired plant in Colorado. The capital expenditure forecast also includes the early stages of the costs related to the MERP modifications to reduce the emissions of NSP-Minnesota’s generating plants located in the Minneapolis-St. Paul metropolitan area. The MERP project is expected to cost approximately $1 billion, with major construction starting in 2005 and finishing in 2009. Xcel Energy expects to recover the costs of the emission-reduction project through customer rate increases beginning in 2006.

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 electric and natural gas 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 restructuring requirements, compliance with future requirements to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements. For more information, see Note 17 to the Consolidated Financial Statements.

Xcel Energy’s investment in exempt wholesale generators and foreign utility companies is currently limited to 100 percent of consolidated retained earnings as a result of the PUHCA restrictions. At this time, Xcel Energy has no capacity to make additional investments in exempt wholesale generators and foreign utility companies without authorization from the SEC.

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Contractual Obligations and Other Commitments — Xcel Energy has contractual obligations and other commercial commitments that will need to be funded in the future, in addition to its capital expenditure programs. The following is a summarized table of contractual obligations and other commercial commitments at Dec. 31, 2003. See additional discussion in the Consolidated Statements of Capitalization and Notes 4, 5, 6, 8, 15 and 17 to the Consolidated Financial Statements.

(a) Under some leases, Xcel Energy would have to sell or purchase the property that it leases if it chose to terminate before the scheduled lease expiration date. Most of Xcel Energy’s railcar, vehicle and equipment, and aircraft leases have these terms. At Dec. 31, 2003, the amount that Xcel Energy would have to pay if it chose to terminate these leases was approximately $142.9 million.

(b) Obligations to purchase fuel for electric generating plants, and electricity and natural gas for resale. Energy costs are largely recoverable from customers in rates. In addition, approximately $2 billion of the obligation is based on prices tied to a commodity index; as such the obligation will change as the commodity index changes.

(c) Xcel Energy also has outstanding authority under contracts and blanket purchase orders to purchase up to $600 million of goods and services through the year 2020, in addition to the amounts disclosed in this table and in the forecasted capital expenditures.

In addition, Xcel Energy’s board of directors approved the repurchase of 2.5 million shares of common stock to fulfill the requirements of the restricted stock unit exercise in 2004.

Common Stock Dividends — Future dividend levels will be dependent upon the statutory limitations discussed below, as well as Xcel Energy’s results of operations, financial position, cash flows and other factors, and will be evaluated by the Xcel Energy board of directors. The ultimate dividend policy will balance:

	•		projected cash generation from utility operations;
	•		projected capital investment in the utility businesses;
	•		reasonable rate of return on shareholder investment; and
	•		impact on Xcel Energy’s capital structure and credit ratings.

Under PUHCA, unless there is an order from the SEC, a holding company or any subsidiary may only declare and pay dividends out of retained earnings. Xcel Energy had $369 million of retained earnings at Dec. 31, 2003, and expects to declare dividends as scheduled. The cash to pay dividends to Xcel Energy shareholders is primarily derived from dividends received from the utility subsidiaries. The utility subsidiaries are generally limited in the amount of dividends allowed by state regulatory commissions to be paid to the holding company. The limitation is imposed through equity ratio limitations that range from 30 percent to 57 percent. All utility subsidiaries are required under PUHCA to pay dividends only from retained earnings, and some must comply with covenant restrictions under credit agreements for debt and interest coverage ratios.

The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy’s capitalization ratio (on a holding company basis only, i.e., not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to common stock plus surplus divided by the sum of common stock plus surplus plus long-term debt. Based on this definition, Xcel Energy’s capitalization ratio at Dec. 31, 2003, was 83 percent. Therefore, the restrictions do not place any effective limit on Xcel Energy’s ability to pay dividends because the restrictions are only triggered when the capitalization ratio is less than 25 percent or will be reduced to less than 25 percent through dividends (other than dividends payable in common stock), distributions or acquisitions of Xcel Energy common stock.

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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.

Registered holding companies and certain of their subsidiaries, including Xcel Energy and its utility subsidiaries, are limited under PUHCA in their ability to issue securities. Such registered holding companies and their subsidiaries may not issue securities unless authorized by an exemptive rule or order of the SEC. Because Xcel Energy does not qualify for any of the main exemptive rules, it sought and received financing authority from the SEC under PUHCA for various financing arrangements. Xcel Energy’s current financing authority permits it, subject to satisfaction of certain conditions, to issue through June 30, 2005, up to $2.5 billion of common stock and long-term debt and $1.5 billion of short-term debt at the holding-company level. Xcel Energy has issued $2 billion of long-term debt and common stock, including the $400 million credit facility.

Xcel Energy’s ability to issue securities under the financing authority is subject to a number of conditions. One of the conditions of the financing authority is that Xcel Energy’s consolidated ratio of common equity to total capitalization be at least 30 percent. As of Dec. 31, 2003, the common equity ratio was approximately 43 percent. Additional conditions require that a security to be issued that is rated, be rated investment grade by at least one nationally recognized rating agency. Finally, all outstanding securities (except preferred stock) that are rated must be rated investment grade by at least one nationally recognized rating agency. On Feb. 20, 2004, Xcel Energy’s senior unsecured debt was considered investment grade by Standard & Poor’s Ratings Services (Standard & Poor’s) and Moody’s Investors Services, Inc. (Moody’s).

Short-Term Funding Sources — Historically, Xcel Energy has used a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend in large part on financing needs for construction expenditures. Another significant short-term funding need is the dividend payment.

In 2003, Xcel Energy established a money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The money pool allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The money pool arrangement does not allow loans from the utility subsidiaries to the holding company. State regulatory commission approval of the arrangement is pending.

As of Feb. 20, 2004, Xcel Energy had the following credit facilities available to meet its liquidity needs:

	*		Includes short-term borrowings and letters of credit.
	**		The SPS $100 million facility expired in February 2004 and was replaced with a $125 million unsecured, 364-day credit agreement.
	***		Reflects the $400 million NRG payment made in February 2004.

Operating cash flow as a source of short-term funding is affected by such operating factors as weather; regulatory requirements, including rate recovery of costs; environmental regulation compliance and industry deregulation; changes in the trends for energy prices; and supply and operational uncertainties, which are difficult to predict. See further discussion of such factors under Statement of Operations Analysis.

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Short-term borrowing as a source of funding is affected by regulatory actions and access to reasonably priced capital markets. For additional information on Xcel Energy’s short-term borrowing arrangements, see Note 5 to the Consolidated Financial Statements. Access to reasonably priced capital markets is dependent in part on credit agency reviews and ratings. The following ratings reflect the views of Moody’s and Standard & Poor’s. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating company. As of Feb. 20, 2004, the following represents the credit ratings assigned to various Xcel Energy companies:

Note: Moody’s highest credit rating for debt is Aaa1 and lowest investment grade rating is Baa3. Standard & Poor’s highest credit rating for debt is AAA+ and lowest investment grade rating is BBB-. Moody’s prime ratings for commercial paper range from P1 to P3. NP denotes a nonprime rating. Standard & Poor’s ratings for commercial paper range from A1 to A3, B and C. As of Feb. 10, 2004, Moody’s had Xcel Energy and its operating utility subsidiaries “under review for possible upgrade.” Standard & Poor’s had Xcel Energy and its operating utility subsidiaries on “credit watch positive.”

In the event of a downgrade of its credit ratings below investment grade, Xcel Energy may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy all or a part of its exposures under guarantees outstanding. See a list of guarantees at Note 15 to the Consolidated Financial Statements. Xcel Energy has no explicit rating triggers in its debt agreements.

Registration Statements — Xcel Energy’s Articles of Incorporation authorize the issuance of one billion shares of common stock. As of Dec. 31, 2003, Xcel Energy had approximately 399 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. On Dec. 31, 2003, Xcel Energy had approximately 1 million shares of preferred stock outstanding. Xcel Energy and its subsidiaries have the following registration statements on file with the SEC, pursuant to which they may sell, from time to time, securities:

	•		In February 2002, Xcel Energy filed a $1 billion shelf registration with the SEC. Xcel Energy may issue debt securities, common stock and rights to purchase common stock under this shelf registration. Xcel Energy has approximately $482.5 million remaining under this registration.
	•		In April 2001, NSP-Minnesota filed a $600 million, long-term debt shelf registration with the SEC. NSP-Minnesota has approximately $40 million remaining under this registration.
	•		PSCo has an effective shelf registration statement with the SEC under which $800 million of secured first collateral trust bonds or unsecured senior debt securities were registered. PSCo has approximately $225 million remaining under this registration.

Future Financing Plans

Xcel Energy generally expects to fund its operations and capital investments through internally generated funds. Xcel Energy plans to renew its credit facilities at NSP-Minnesota, PSCo and SPS during 2004 and may refinance existing long-term debt with lower-rate debt, based on market conditions. See discussion of funding for the NRG settlement payments in the following section.

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Impact of Settlement Agreement with NRG

As discussed previously and in Note 4 to the Consolidated Financial Statements, NRG has completed its plan of reorganization through a bankruptcy proceeding, and the terms of a settlement among NRG, Xcel Energy and members of NRG’s major creditor constituencies was approved and put into effect.

As part of the reorganization, Xcel Energy completely divested its ownership interest in NRG, which in turn issued new common equity to its creditors. The financial terms of the settlement agreement included a provision that Xcel Energy will pay $752 million to NRG to settle all claims of NRG against Xcel Energy and claims of NRG creditors against Xcel Energy under the NRG plan of reorganization as follows:

	•		$400 million paid on Feb. 20, 2004, including $112 million to NRG’s bank lenders.
	•		$352 million will be paid on April 30, 2004, unless at such time Xcel Energy has not received tax refunds equal to at least $352 million associated with the loss on its investment in NRG. To the extent such refunds are less than the required payments, the difference between the required payments and those refunds would be due on May 30, 2004.
	•		In return for such payments, Xcel Energy received, or was granted, voluntary and involuntary releases from NRG and its creditors.

Xcel Energy intends to fund the payments required by the settlement agreement with cash received for tax benefits related to its investment in NRG, cash on hand and available Xcel Energy credit facilities.

Based on current forecasts of taxable income and tax liabilities, Xcel Energy expects to realize approximately $1.1 billion of cash savings from these tax benefits through a refund of taxes paid in prior years and reduced taxes payable in future years. Xcel Energy used $130 million of these tax benefits in 2003 and expects to use $480 million in 2004. The remainder of the tax benefit carry forward is expected to be used over subsequent years.

Off-Balance-Sheet Arrangements

Xcel Energy does not have any off-balance-sheet arrangements that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Earnings Guidance

Xcel Energy’s 2004 earnings per share from continuing operations guidance and key assumptions are detailed in the following table.

Key Assumptions for 2004:

	•		NRG has no impact on Xcel Energy’s financial results in 2004;
	•		normal weather patterns throughout 2004;
	•		weather-adjusted retail electric utility sales growth of 2.2 percent;
	•		weather-adjusted firm retail gas utility sales growth of approximately 2.4 percent;
	•		successful outcome of the requested capacity rider revenue increase in Colorado;
	•		2004 trading and short-term wholesale margins are expected to be slightly less than 2003 margins to reflect more normal market conditions;
	•		2004 utility operating and maintenance expense is expected be relatively flat, compared with 2003 levels;
	•		2004 depreciation expense is projected to increase by about 2 percent compared with 2003;
	•		2004 interest expense is projected to decline by approximately $15 million, compared with 2003 levels;
	•		an effective tax rate of approximately 31 percent; and
	•		average common stock and equivalents of approximately 425 million shares in 2004, based on the “If Converted” method for convertible notes.

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INDEPENDENT AUDITORS’ REPORT

To Xcel Energy Inc.:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Xcel Energy Inc. (a Minnesota corporation) and subsidiaries (the Company) as of December 31, 2003 and 2002, and the related consolidated statements of operations, common stockholders’ equity and other comprehensive income and cash flows for the three years ended December 31, 2003. These consolidated 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 did not audit the consolidated balance sheet of NRG Energy, Inc. (a wholly owned subsidiary of Xcel Energy Inc.) for the year ended December 31, 2002, or the consolidated statements of operations, stockholder’s (deficit)/equity and cash flows for the two years ended December 31, 2002 included in the consolidated financial statements of the Company, which statements reflect total assets of $10.9 billion as of December 31, 2002 and losses from discontinued operations net of tax of $3.5 billion for the year ended December 31, 2002,and income from discontinued operations net of tax of $265 million for the year ended December 31, 2001. Those statements were audited by other auditors whose report has been furnished to us (which as to 2002 expresses an unqualified opinion and includes an explanatory paragraph describing conditions that raise substantial doubt about NRG Energy, Inc.’s ability to continue as a going concern and emphasis of a matter paragraph related to the adoption of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets” and SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” on January 1, 2002), and our opinion, insofar as it relates to the amounts included for NRG Energy, Inc. for the periods described above, is based solely on the report of the other auditors.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Xcel Energy Inc. and subsidiaries as of December 31, 2003 and 2002 and the results of their operations and their cash flows for each of the three years ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2002, Xcel Energy Inc. and subsidiaries adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” and SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”

As discussed in Note 18 to the consolidated financial statements, effective January 1, 2003, Xcel Energy Inc. and subsidiaries adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” and as discussed in Note 16, effective October 1, 2003, Derivatives Implementation Group Issue No. C20 “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature.”

/s/ DELOITTE & TOUCHE LLP
Deloitte & Touche LLP

Minneapolis, Minnesota
February 27, 2004

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholder
of NRG Energy, Inc.:

In our opinion, the consolidated balance sheets and the related consolidated statements of operations, cash flows and stockholder’s (deficit)/equity (not presented separately herein) present fairly, in all material respects, the financial position of NRG Energy, Inc. and its subsidiaries at December 31, 2002, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. 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 of America, 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 our audits provide a reasonable basis for our opinion.

The consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 and Note 29 to the consolidated financial statements, the Company is experiencing credit and liquidity constraints and has various credit arrangements that are in default. As a direct consequence, during 2002 the Company entered into discussions with its creditors to develop a comprehensive restructuring plan. In connection with its restructuring efforts, the Company and certain of its subsidiaries filed for Chapter 11 bankruptcy protection. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 19 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” for the year ended December 31, 2002. As discussed in Notes 3 and 5 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” on January 1, 2002.

/S/ PRICEWATERHOUSECOOPERS LLP
PricewaterhouseCoopers LLP
Minneapolis, Minnesota
March 28, 2003, except as to Notes 29 and 30, which are as of December 3, 2003.

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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

(Thousands of dollars, except per share data)

See Notes to Consolidated Financial Statements.

31

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)