Xcel Energy

table of contents

consolidated financial statements  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . page  44
notes to consolidated financial statements  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . page 
51
shareholder information  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . page 101
xcel energy directors and principal officers  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . page 102

management ’s discussion and analysis

On Aug. 18, 2000, New Century Energies, Inc. (NCE) and Northern States Power Co. (NSP) merged and formed Xcel Energy Inc.
(Xcel Energy). Xcel Energy, a Minnesota corporation, is a registered holding company under the Public Utility Holding Company Act
(PUHCA). As part of the merger, NSP transferred its existing utility operations that were being conducted directly by NSP at the
parent company level to a newly formed subsidiary of Xcel Energy named Northern States Power Co. Each share of NCE common
stock was exchanged for 1.55 shares of Xcel Energy common stock. NSP shares became Xcel Energy shares on a one-for-one basis.
As a stock-for-stock exchange for shareholders of both companies, the merger was accounted for as a pooling-of-interests and, accordingly,
amounts reported for periods prior to the merger have been restated for comparability with post-merger results.

Xcel Energy directly owns six utility subsidiaries that serve electric and natural gas customers in 12 states. These six 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); Black Mountain Gas Co.
(BMG), which is in the process of being sold pending regulatory approval; and Cheyenne Light, Fuel and Power Co. (Cheyenne).
They serve customers in portions of Arizona, Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma,
South Dakota, Texas, Wisconsin and Wyoming. During 2002, Xcel Energy’s regulated businesses also included Viking Gas
Transmission Co. (Viking), which was sold on Jan. 17, 2003, and WestGas InterState Inc. (WGI), both interstate natural gas
pipeline companies.

Xcel Energy also owns or has an interest in a number of nonregulated businesses, the largest of which is NRG Energy, Inc. (NRG), an
independent power producer. Xcel Energy owned 100 percent of NRG at the beginning of 2000. About 18 percent of NRG was sold to
the public in an initial public offering in the second quarter of 2000, leaving Xcel Energy with an 82-percent interest at Dec. 31, 2000. In
March 2001, another 8 percent of NRG was sold to the public, leaving Xcel Energy with an interest of about 74 percent at Dec. 31, 2001.
On June 3, 2002, Xcel Energy acquired the 26 percent of NRG held by the public so that it again held 100 percent ownership at
Dec. 31, 2002. NRG is facing extreme financial difficulties. There is substantial doubt as to NRG’s ability to continue as a going
concern absent a restructuring through bankruptcy, and NRG will likely be the subject of a bankruptcy proceeding. See Notes 2, 3, 4
and 7 to the Consolidated Financial Statements.

In addition to NRG, Xcel Energy’s nonregulated subsidiaries include Utility Engineering Corp. (engineering, construction and design),
Seren Innovations, Inc. (broadband telecommunications services), e prime inc. (natural gas marketing and trading), Planergy International,
Inc. (enterprise energy management solutions), Eloigne Co. (investments in rental housing projects that qualify for low-income housing tax
credits) and Xcel Energy International Inc. (an international independent power producer).

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.

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-
looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to
be identified in this document by the words “anticipate,” “estimate,” “expect,” “objective,” “outlook,” “project,” “possible,” “potential”
and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are
not limited to: general economic conditions, including their impact on capital expenditures 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; currency translation
and transaction adjustments; 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, 2002.

page 16

xcel energy inc. and subsidiaries

management ’s discussion and analysis

Xcel Energy’s earnings per share for the past three years were as follows:

results of operations

Contribution to earnings per share

Continuing operations before extraordinary items:

Regulated utility
NRG (including impairments and restructuring charges)
Other nonregulated/holding company (including tax 
benefits related to investment in NRG in 2002)
Income (loss) from continuing operations

Discontinued operations – NRG (see Note 3)
Extraordinary items – Regulated utility (see Note 15)
Total earnings (loss) per share – diluted

Additional information on earnings contributions by operating segments are as follows:

Contribution to earnings per share

Regulated utility (including extraordinary items):

Electric utility 
Gas utility 

Total regulated utility 

NRG (including discontinued operations) (see Note 3)
Other nonregulated/holding company:

Tax benefit related to investment in NRG
Other (see Note 21 for components)

Total earnings (loss) per share – diluted

2002

2001

2000

$ 1.59
(7.58)

1.63
(4.36)
(1.46)
–
$(5.82)

$ 1.90
0.44

(0.21)
2.13
0.14
0.03
$ 2.30

$ 1.20
0.37

(0.06)
1.51
0.09
(0.06)
$ 1.54

2002

2001

2000

$ 1.33
0.26
1.59
(9.04)

1.85
(0.22)
$(5.82)

$ 1.66
0.24
1.90
0.58

–
(0.18)
$ 2.30

$ 1.03
0.17
1.20
0.46

–
(0.12)
$ 1.54

For more information on significant factors that had an impact on earnings, see below.

significant factors that impacted 2002 results

Special Charges – Regulated Utility 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 early in the year for utility and service company operations. See Note 2 to the Consolidated Financial Statements for
further discussion of these items, which are reported as Special Charges in operating expenses.

Impairment and Financial Restructuring Charges – NRG NRG’s losses from both continuing and discontinued operations were affected
by charges recorded in 2002. Continuing operations included losses of approximately $7.07 per share in 2002 for asset impairment
and disposal losses, and for other charges related mainly to its financial restructuring. These costs are reported as Special Charges
and Write-downs and Disposal Losses from Investments in operating expenses, and are discussed further in Note 2 to the Consolidated
Financial Statements. In addition, discontinued operations included losses of approximately $1.56 per share for asset impairments
and disposal losses, and are discussed further in Note 3 to the Consolidated Financial Statements.

During 2002, NRG experienced credit-rating downgrades, defaults under certain credit agreements, increased collateral requirements
and reduced liquidity. These events led to impairment reviews of a number of NRG assets, which resulted in material write-downs in
2002. In addition to impairments of projects operating or under development, certain NRG projects were determined to be held for
sale, and estimated losses on disposal for such projects were also recorded. These impairment charges, some of which related to equity
investments, have reduced Xcel Energy’s earnings for 2002 as follows: $6.29 of Special Charges in continuing operations, $0.51 of
Losses on Disposal of Investments in continuing operations and $1.57 of impairment charges included in discontinued operations. As
reported previously, there is substantial doubt as to NRG’s ability to continue as a going concern, and NRG will likely be the subject of 
a bankruptcy proceeding.

NRG also expensed approximately $111 million in 2002 for incremental costs related to its financial restructuring and business realignment.
These costs, which reduced 2002 earnings by 27 cents per share, include expenses for financial and legal advisors, contract termination costs,
employee separation and other incremental costs incurred during the financial restructuring period. These costs also include a charge related
to NRG’s NEO landfill gas generation operations for the estimated impact of a dispute settlement with NRG’s partner on the NEO project,
Fortistar. Most of these costs were paid in 2002. See Note 2 to the Consolidated Financial Statements for discussion of accrued financial
restructuring cost activity related to NRG.

xcel energy inc. and subsidiaries          page 17

management ’s discussion and analysis

Tax Benefit – NRG Investment As discussed in Note 11 to the Consolidated Financial Statements, it was determined in 2002 that NRG was
no longer likely to be included in Xcel Energy’s consolidated income tax group. Approximately $706 million has been recognized at one of
Xcel Energy’s nonregulated intermediate holding companies for the estimated tax benefits related to Xcel Energy’s investment in NRG, based
on the difference between book and tax bases of such investment. This estimated tax benefit increased 2002 annual results by $1.85 per share.

Other Nonregulated and Holding Companies Nonregulated and holding company earnings for 2002 were reduced by losses of
approximately 6 cents per share for the combined effects of unusual items that occurred during the year. As discussed later, Xcel
International recorded impairment losses for Argentina assets of 3 cents per share and disposal losses for Yorkshire Power of 2 cents per
share, Planergy recorded gains from contract sales of 2 cents per share, losses were incurred on holding company debt of 2 cents per share,
and incremental costs related to NRG financial restructuring activities of 1 cent per share were incurred at the holding company level.

significant factors that impacted 2001 results

Regulated utility earnings were reduced by a net 1 cent per share from the combined effects of four unusual items that occurred during
the year. Three of the items affected continuing operations, reducing earnings by 4 cents per share. The remaining item increased income
from extraordinary items by 3 cents per share.

Conservation Incentive Recovery Regulated utility earnings from continuing operations in 2001 were increased by 7 cents per share due
to a Minnesota Public Utilities Commission (MPUC) decision. In June 2001, the MPUC approved a plan allowing recovery of 1998
incentives associated with state-mandated programs for energy conservation. As a result, the previously recorded liabilities of approximately
$41 million, including carrying charges, for potential refunds to customers were no longer required. The plan approved by the MPUC
increased revenue by approximately $34 million and increased allowance for funds used during construction by approximately $7 million,
increasing earnings by 7 cents per share for the second quarter of 2001. Based on the new MPUC policy and less uncertainty regarding
conservation incentives to be approved, conservation incentives are being recorded on a current basis beginning in 2001.

Special Charges – Postemployment Benefits and Restaffing Costs Regulated utility earnings from continuing operations in 2001 were
decreased 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 postemployment 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. See Note 2 to
the Consolidated Financial Statements for further discussion of these items, which are reported as Special Charges in operating expenses.

Extraordinary Items – Electric Utility Restructuring In 2001, extraordinary income of $18 million before tax, or 3 cents per share, was
recorded related to the regulated utility business to reflect the impacts of industry restructuring developments for SPS. This represents a
reversal of a portion of the 2000 extraordinary loss discussed later. For more information on SPS extraordinary items, see Note 15 to the
Consolidated Financial Statements.

significant factors that impacted 2000 results

Special Charges – Merger Costs During 2000, Xcel Energy expensed pretax special charges of $241 million, or 52 cents per share, for
costs related to the merger between NSP and NCE. Of these special charges, approximately 44 cents per share were associated with the
costs of merging regulated utility operations and 8 cents per share were associated with merger impacts on nonregulated and holding
company activities other than NRG. See Note 2 to the Consolidated Financial Statements for more information on these merger-
related costs reported as Special Charges.

Extraordinary Items – Electric Utility Restructuring In 2000, extraordinary losses of approximately $28 million before tax, or 6 cents per
share, were recorded related to the regulated utility business for the expected discontinuation of regulatory accounting for SPS’ generation
business. For more information on SPS extraordinary items, see Note 15 to the Consolidated Financial Statements.

statement of operations analysis

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. However, the fuel clause
cost recovery in Colorado does not allow for complete recovery of all variable production expense, and cost changes can affect earnings.
Electric utility margins reflect the impact of sharing energy costs and savings relative to a target cost per delivered kilowatt-hour and
certain trading margins under the incentive cost adjustment (ICA) ratemaking mechanism in Colorado. In addition to the ICA,
Colorado has other adjustment clauses that allow certain costs to be recovered from retail customers.

Xcel Energy has three distinct forms of wholesale sales: short-term wholesale, electric commodity trading and natural gas 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 and natural gas commodity trading refers to the sales for resale
activity of purchasing and reselling electric and natural gas energy to the wholesale market.

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xcel energy inc. and subsidiaries

management ’s discussion and analysis

Xcel Energy’s commodity trading operations are conducted by NSP-Minnesota (electric), PSCo (electric) and e prime (natural gas).
Margins from electric trading activity, conducted at NSP-Minnesota and PSCo, 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).
Trading margins reflect the impact of sharing certain trading margins under the ICA. Trading revenues, as discussed in Note 1 to the
Consolidated Financial Statements, are reported net (i.e., margins) in the Consolidated Statements of Operations. Trading revenue
and costs associated with NRG’s operations are included in nonregulated margins. The following table details the revenue and margin
for base electric utility, short-term wholesale and electric and natural gas trading activities.

(Millions of dollars)

2002

Electric utility revenue
Electric fuel and purchased power – utility
Electric and natural gas trading revenue – gross
Electric and natural gas trading costs
Gross margin before operating expenses
Margin as a percentage of revenue

2001

Electric utility revenue
Electric fuel and purchased power – utility
Electric and natural gas trading revenue – gross
Electric and natural gas trading costs
Gross margin before operating expenses
Margin as a percentage of revenue

2000

Electric utility revenue
Electric fuel and purchased power – utility
Electric and natural gas trading revenue – gross
Electric and natural gas trading costs
Gross margin before operating expenses
Margin as a percentage of revenue

Base
Electric
Utility

Short-Term
Wholesale

$  5,232
(2,029)
–
–
$  3,203
61.2%

$ 5,607
(2,559)
–
–
$ 3,048
54.4%

$ 5,107
(2,106)
–
–
$ 3,001
58.8%

$    203
(170)
–
–
$      33
16.3%

$ 788
(613)
–
–
$ 175
22.2%

$ 567
(475)
–
–
92
$
16.2%

Electric Natural Gas
Commodity

Commodity
Trading

Trading Eliminations

Intercompany Consolidated
Totals

$        –
–
1,529
(1,527)
$        2
0.1%

$

–
–

1,337  
(1,268)
69
$
5.2%

$

$

–
–
819  
(788)
31
3.8%

$        –
–
1,898
(1,892)
$        6
0.3%

$

–
–
1,938
(1,918)
$     20
1.0%

$

–
–
1,297
(1,287)
$     10
0.8%

$        –
–
(71)
71
$        –
–

$

$

$

$

–
–
(88)
88
–
–

–
–
(54)
54
–
–

$  5,435
(2,199)
3,356
(3,348)
$  3,244
36.9%

$ 6,395
(3,172)
3,187
(3,098)
$ 3,312
34.6%

$ 5,674
(2,581)
2,062
(2,021)
$  3,134
40.5%

2002 Comparison to 2001 Base electric utility revenue decreased $375 million, or 6.7 percent, while electric utility margins, primarily
retail, increased approximately $155 million, or 5.1 percent, in 2002, compared with 2001. Base electric revenues decreased largely due
to decreased recovery of fuel and purchased power costs driven by declining fuel costs in 2002. The higher base electric margins in the
year reflect lower unrecovered costs, due in part to resetting the base-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 cost. For the year, higher accrued conservation revenues, sales growth and more favorable temperatures also contributed
to the higher electric margins and partially offset the lower base electric revenue. Lower wholesale capacity sales in Texas, as well as the
impact of the conservation incentive adjustment in Minnesota in 2001, as discussed previously, partially offset the increased margins and
contributed to the lower revenues.

Short-term wholesale margins consist of asset-based trading activity. Electric and natural gas commodity trading activity margins consist
of non-asset-based trading activity. Short-term wholesale and electric and natural gas commodity trading sales margins decreased an
aggregate of approximately $223 million, or 84.5 percent, in 2002, compared with 2001. The decrease in short-term wholesale and
electric commodity trading margin reflects lower power prices and less favorable market conditions. The decrease in natural gas
commodity trading margin reflects reduced market opportunities.

2001 Comparison to 2000 Base electric utility revenue increased by approximately $500 million, or 9.8 percent, in 2001. Base electric
utility margin increased by approximately $47 million, or 1.6 percent, in 2001. These revenue and margin increases were due to
sales growth, weather conditions in 2001 and the recovery of conservation incentives in Minnesota. Increased conservation incentives,
including the resolution of the 1998 dispute, as discussed previously, and accrued 2001 incentives, increased revenue and margin by
$49 million. More favorable weather during 2001 increased revenue by approximately $23 million and margin by approximately
$13 million. These increases were partially offset by increases in fuel and purchased power costs, which are not completely recoverable
from customers in Colorado due to various cost-sharing mechanisms. Revenue and margin also were reduced in 2001 by approximately
$30 million due to rate reductions in various jurisdictions agreed to as part of the merger approval process, compared with $10 million
in 2000.

xcel energy inc. and subsidiaries          page 19

management ’s discussion and analysis

Short-term wholesale revenue increased by approximately $221 million, or 39 percent, in 2001. Short-term wholesale margin increased
$83 million, or 90.2 percent, in 2001. These increases are due to the expansion of Xcel Energy’s wholesale marketing operations and
favorable market conditions for the first six months of 2001, including strong prices in the western markets, particularly before the
establishment of price caps and other market changes.

Electric and natural gas commodity trading margins, including proprietary electric trading (i.e., not in electricity produced by Xcel
Energy’s own generating plants) and natural gas trading, increased approximately $48 million for the year ended Dec. 31, 2001, compared
with the same period in 2000. The increase reflects an expansion of Xcel Energy’s trading operations and favorable market conditions,
including strong prices in the western markets, particularly before the establishment of price caps and other market changes.

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 natural gas purchases. However, due to purchased natural gas cost
recovery mechanisms for retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.

(Millions of dollars)

Natural gas utility revenue
Cost of natural gas purchased and transported

Natural gas utility margin

2002

$ 1,398
(852)
$ 546

2001

$ 2,053
(1,518)
$ 535

2000

$ 1,469
(948)
$ 521

2002 Comparison to 2001 Natural gas utility revenue decreased by $655 million, or 31.9 percent, while natural gas margins increased by
$11 million, or 2.1 percent. Natural gas revenue decreased largely due to decreases in the cost of natural gas, which are generally passed
through to customers. Natural gas utility margin increased due primarily to more favorable temperatures and sales growth.

2001 Comparison to 2000 Natural gas utility revenue increased by approximately $584 million, or 39.8 percent, for 2001, primarily due
to increases in the cost of natural gas, which are largely passed on to customers and recovered through various rate adjustment clauses in
most of the jurisdictions in which Xcel Energy operates. Natural gas utility margin increased by approximately $14 million, or 2.7 percent,
for 2001 due to sales growth and a rate increase in Colorado. These natural gas revenue and margin increases were partially offset by the
impact of warmer temperatures in 2001, which decreased natural gas revenue by approximately $38 million and natural gas margin by
approximately $16 million.

Nonregulated Operating Margins The following table details the changes in nonregulated revenue and margin included in 
continuing operations.

(Millions of dollars)

Nonregulated and other revenue
Earnings from equity investments
Nonregulated cost of goods sold

Nonregulated margin

2002

$2,611
72
(1,361)
$ 1,322

2001

$2,580
217
(1,319)
$ 1,478

2000

$1,856
183
(877)
$ 1,162

2002 Comparison to 2001 Nonregulated revenue from continuing operations increased slightly in 2002, reflecting growth from the
full-year impact of NRG’s 2001 generating facility acquisitions but partially offset by lower market prices. Nonregulated margin from
continuing operations decreased in 2002, due to decreased equity earnings. Earnings from equity investments for 2002 decreased
compared with 2001, primarily due to decreased equity earnings from NRG’s West Coast Power project, which experienced less
favorable long-term contracts and higher uncollectible receivables.

2001 Comparison to 2000 Nonregulated revenue and margin from continuing operations increased in 2001, largely due to NRG’s
acquisition of generating facilities, increased demand for electricity, market dynamics, strong performance from existing assets and higher
market prices for electricity. Earnings from equity investments for 2001 increased compared with 2000, primarily due to increased equity
earnings from NRG projects, which offset lower equity earnings from Yorkshire Power. As a result of a sales agreement to sell most of its
investment in Yorkshire Power, Xcel Energy did not record any equity earnings from Yorkshire Power after January 2001.

Non-Fuel Operating Expense and Other Items Other utility operating and maintenance expense for 2002 decreased by approximately
$4 million, or 0.3 percent. The decreased costs reflect lower incentive compensation and other employee benefit costs, as well as lower
staffing levels in corporate areas. These decreases were substantially offset by higher plant outage and property insurance costs, in addition
to inflationary factors such as market wage increases.

Other utility operating and maintenance expense for 2001 increased by approximately $60 million, or 4.1 percent, compared with 2000.
The change is largely due to increased plant outages, higher nuclear operating costs, bad debt reserves reflecting higher energy prices,
increased costs due to customer growth and higher performance-based incentive costs.

Other nonregulated operating and maintenance expenses for continuing operations increased $111 million in 2002 and increased
$143 million in 2001. These expenses are included in the results for each nonregulated subsidiary, as discussed later.

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xcel energy inc. and subsidiaries

management ’s discussion and analysis

Depreciation and amortization expense increased $131 million, or 14.5 percent, in 2002 and $140 million, or 18.2 percent, in 2001,
primarily due to acquisitions of generating facilities by NRG and additions to utility plant. Higher NRG depreciation expense
accounted for $87 million of the increase in 2002.

Interest income was higher in 2002 and 2001 due to higher cash balances at NRG in both years and to interest on affiliate loans in 2001.

Other income was higher in 2002 and 2001 due mainly to a gain on the sale of nonregulated property and PSCo assets.

Other expense increased in 2002 due largely to variations in currency exchange losses at NRG.

Interest expense increased $152 million, or 20.8 percent, in 2002 and $114 million, or 18.5 percent, in 2001, primarily due to increased
debt of NRG. In addition, long-term debt was refinanced at higher interest rates during 2002. Higher NRG interest expense accounted
for $105 million of the increase in 2002.

Income tax expense decreased by approximately $959 million in 2002, compared with 2001. Nearly all of this decrease relates to NRG’s
2002 losses and the change in tax filing status for NRG effective in the third quarter of 2002, as discussed in Note 11 to the Consolidated
Financial Statements. NRG is now in a tax operating loss carry forward position and is no longer assumed to be part of Xcel Energy’s
consolidated tax group. The effective tax rate for continuing operations, excluding minority interest and before extraordinary items, was
27.3 percent for the year ended Dec. 31, 2002, and 28.8 percent for the same period in 2001. The decrease in the effective rate between
years reflects a nominal tax rate at NRG due to its loss carry forward position. Partially offsetting the NRG tax rate decrease is the impact of
a one-time adjustment to recognize tax benefits from Xcel Energy’s investment in NRG, as discussed in Note 11 to the Consolidated
Financial Statements. The effective tax rate for the regulated utility business and operations other than NRG was significantly lower
in 2002, compared with 2001, due to the benefit recorded on the investment in NRG and the changes in the items listed in the rate
reconciliation in Note 11.

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, which may not be fully recoverable. Unseasonably mild weather reduces electric and natural
gas sales, but may not reduce expenses, which affects overall results. 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 2002 increased earnings by an estimated 6 cents per share;
– weather in 2001 had minimal impact on earnings per share; and
– weather in 2000 increased earnings by an estimated 1 cent per share.

nrg results
Contribution to Xcel Energy’s earnings per share

Continuing NRG operations:

Operations before tax credits, special charges and disposal losses
Tax credits
Special charges – asset impairments (Note 2)
Special charges – financial restructuring and NEO (Note 2)
Write-downs and disposal losses from equity investments (Note 2)

Income (loss) from continuing NRG operations

Discontinued NRG operations (Note 3) 

Total NRG earnings (loss) per share
Minority shareholder interest
NRG contribution to Xcel Energy

2002

2001

2000

$ (0.54)
–
(6.29)
(0.27)
(0.51)
(7.61)
(1.46)
(9.07)
0.03
$ (9.04)

$ 0.49
0.14
–
–
–
0.63
0.14
0.77
(0.19)
$ 0.58

$ 0.35
0.10
–
–
–
0.45
0.09
0.54
(0.08)
$ 0.46

NRG Continuing Operations and Tax Credits As previously stated, NRG is facing extreme financial difficulties, and there is substantial
doubt as to NRG’s ability to continue as a going concern. During 2002, NRG’s continuing 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. During 2002, an additional reserve for uncollectible receivables in
California was established by West Coast Power, which reduced NRG’s equity earnings by approximately $29 million, after tax. West
Coast Power’s 2002 income also was lower than 2001 due to less-favorable contracts and reductions in sales of energy and capacity.
In addition, increased administrative costs, depreciation and interest expense from completed construction costs also contributed to the
less-than-favorable results for NRG in 2002. Partially off-setting these earnings reductions was the recognition, in the fourth quarter of
2002, of approximately $51 million of additional revenues related to the contractual termination related to NRG’s Indian River project.

On a stand-alone basis, NRG does 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 and 2000, which included income related to recognition of tax credits.

xcel energy inc. and subsidiaries          page 21

management ’s discussion and analysis

NRG’s earnings for 2001 increased primarily due to new acquisitions in Europe and North America, as well as a full year of operation in
2001 of acquisitions made in the fourth quarter of 2000. In addition, NRG’s 2001 earnings reflected a reduction in the overall effective
tax rate and mark-to-market gains related to SFAS No. 133 – “Accounting for Derivative Instruments and Hedging Activity.” The overall
reduction in tax rates in 2001 was primarily due to higher energy credits, the implementation of state tax planning strategies and a higher
percentage of NRG’s overall earnings derived from foreign projects in lower tax jurisdictions.

NRG Special Charges – Impairments and Financial Restructuring As discussed previously, both the continuing and discontinued operations
of NRG in 2002 included material losses for asset impairments and estimated disposal losses. Also, NRG recorded other special charges
in 2002, mainly for incremental costs related to its financial restructuring and business realignment. See Notes 2 and 3 to the Consolidated
Financial Statements for further discussion of NRG’s special charges and discontinued operations, respectively.

other nonregulated subsidiaries and holding company results
Contribution to Xcel Energy’s earnings per share

Xcel International
Eloigne Company
Seren Innovations
Planergy International
e prime
Financing costs and preferred dividends
Other nonregulated/holding company results

Subtotal – nonregulated/holding co. excluding tax benefit

Tax benefit from investment in NRG (Note 11) 

Total nonregulated/holding company earnings per share

2002

$(0.05)
0.02
(0.07)
–
–
(0.11)
(0.01)
(0.22)
1.85
$ 1.63

2001

$(0.02)
0.03
(0.08)
(0.04)
0.02
(0.11)
0.02
(0.18)
–
$(0.18)

2000

$ 0.09
0.02
(0.07)
(0.08)
(0.02)
(0.07)
0.01
(0.12)
–
$(0.12)

Xcel International Xcel International currently comprises primarily power generation projects in Argentina, and previously included an
investment in Yorkshire Power.

In December 2002, a subsidiary of Xcel Argentina decided it would no longer fund one of its power projects in Argentina and defaulted
on its loan agreements. The default is not material to Xcel Energy. However, 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 International’s investment. An impairment write-down of approximately $13 million, or 3 cents per share,
was recorded in 2002.

In August 2002, Xcel Energy announced it had sold its 5.25-percent interest in Yorkshire Power Group Limited for $33 million to CE
Electric UK. The sale of the 5.25-percent interest resulted in an after-tax loss of $8.3 million, or 2 cents per share, in 2002. The loss is
included in write-downs and disposal losses from investments on the Consolidated Statements of Operations. Xcel Energy and American
Electric Power Co. initially 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. As a result of this sales agreement, Xcel
Energy did not record any equity earnings from Yorkshire Power after January 2001. For more information, see Note 3 to the
Consolidated Financial Statements.

Eloigne Company Eloigne invests in affordable housing that qualifies for Internal Revenue Service tax credits. Eloigne’s earnings
contribution declined slightly in 2002 as tax credits on mature affordable housing projects began to decline. The actual decline in
Eloigne’s net income in 2002, compared with 2001, was only $716,000, with 2002 earnings representing 2.1 cents per share and
2001 earnings representing 2.5 cents per share.

Seren Innovations Seren operates a combination cable television, telephone and high-speed Internet access system in St. Cloud, Minn., and
Contra Costa County, California. Operation of its broadband communications network has resulted in losses. Seren projects improvement in
its operating results with positive cash flow anticipated in 2005, upon completion of its build-out phase, and a positive earnings contribution
anticipated in 2008.

Planergy International Planergy, a wholly owned subsidiary of Xcel Energy, provides energy management services. Planergy’s results
for 2002 improved, largely due to gains from the sale of a portfolio of energy management contracts, which increased earnings by
nearly 2 cents per share.

Planergy’s results for 2000 were reduced by special charges of 4 cents per share for the write-offs of goodwill and project development costs.

e prime e prime’s results for the year ended Dec. 31, 2001, reflect the favorable structure of its contractual portfolio, including natural
gas storage and transportation positions, structured products and proprietary trading in natural gas markets. e prime’s earnings were
lower in 2002, and higher in 2001, due to varying natural gas commodity trading margins, as discussed previously.

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xcel energy inc. and subsidiaries

management ’s discussion and analysis

e prime’s results for 2000 were reduced by special charges of 2 cents per share for contractual obligations and other costs associated with
post-merger changes in the strategic operations and related revaluations of e prime’s energy marketing business.

Financing Costs and Preferred Dividends Nonregulated results include interest expense and 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 longer-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.

Other Certain costs related to NRG’s restructuring are being incurred at the holding company level. Approximately $5 million of such
costs were incurred in 2002, which reduced earnings by approximately 1 cent per share.

Other nonregulated results for 2000, which include the activity of several nonregulated subsidiaries, were reduced by merger-related
special charges of 2 cents per share. These special charges include $10 million in asset write-downs and losses resulting from various
other nonregulated business ventures that are no longer being pursued after the Xcel Energy merger.

factors affecting results of operations

Xcel Energy’s utility revenues depend on customer usage, which varies with weather conditions, general business conditions and the cost
of energy services. Various regulatory agencies approve the prices for electric and natural gas service within their respective jurisdictions.
In addition, Xcel Energy’s nonregulated businesses have adversely affected Xcel Energy’s earnings in 2002. The historical and future
trends of Xcel Energy’s operating results have been, and are expected to be, affected by the following factors:

Impact of NRG Financial Difficulties NRG is experiencing severe financial difficulties, resulting primarily from declining credit ratings
and lower prices for power. These financial difficulties have caused NRG to miss several scheduled payments of interest and principal
on its bonds and incur approximately $3.1 billion in asset impairment charges. In addition, as a result of being downgraded, NRG was
required to post cash collateral ranging from $1.1 billion to $1.3 billion. NRG has been unable to post this cash collateral and, as a
result, is in default on various obligations. Furthermore, in November 2002, lenders to NRG accelerated approximately $1.1 billion of
NRG’s debt, rendering the debt immediately due and payable. In February 2003, lenders to NRG accelerated an additional $1 billion
of debt. NRG does not contemplate making any principal or interest payments on its corporate-level debt pending the restructuring
of its obligations, and is in default under various debt instruments. As a consequence of the defaults, the lenders are able to seek to
enforce their remedies, if they so choose, and that would likely lead to a bankruptcy filing by NRG. NRG continues to work with its
lenders and bondholders on a comprehensive financial restructuring plan. See further discussion of potential NRG bankruptcy and
financial restructuring under Liquidity and Capital Resources and in Notes 4 and 18 to the Consolidated Financial Statements.

Subsequent to its credit downgrade in July 2002, NRG experienced losses as follows in 2002:

(Millions of dollars)

Third Quarter

Fourth Quarter

Net losses from NRG:
Special charges – asset impairments
Special charges – financial restructuring and other costs
Write-downs and losses on equity method investments
Other income (loss) from continuing operations, including income tax effects

NRG loss from continuing operations
Discontinued operations – asset impairments
Discontinued operations – other
Net NRG loss for period

$(2,466)
(34)
(118)
140
(2,478)
(600)
23
$(3,055)

$ (79)
(21)
(74)
(176)
(350)
–
9
$(341)

These NRG losses have reduced Xcel Energy’s retained earnings to a deficit as of Dec. 31, 2002. NRG is expected to continue to
experience material losses into 2003, pending a successful financial restructuring and increased power prices. NRG’s losses in 2003
may include further asset impairments, losses from asset disposals and financial restructuring costs as NRG continues its financial
restructuring and decisions are made to realign NRG’s business operations and divest operating assets. In addition, the impact of
any settlement with NRG’s creditors regarding the financial restructuring of NRG also may impact Xcel Energy’s operating results and
retained earnings by material amounts that will not be determinable until settlement terms are reached. See Note 4 to the Consolidated
Financial Statements for a discussion of a preliminary settlement with NRG’s creditors. As discussed later, Xcel Energy is unable, without
SEC approval under PUHCA, to declare dividends on its common stock until consolidated retained earnings are positive, and continuing
NRG financial impacts may continue to limit the ability of Xcel Energy to declare and pay dividends.

xcel energy inc. and subsidiaries          page 23

management ’s discussion and analysis

In the event that NRG’s financial situation ultimately results in a bankruptcy filing, there may be additional impacts on Xcel Energy’s
financial condition and results of operations. See the Xcel Energy Impacts under the Other Liquidity and Capital Resource Considerations
section later in Management’s Discussion and Analysis, and Note 4 to the Consolidated Financial Statements for further discussion
of the possible effects of an NRG bankruptcy filing on Xcel Energy.

General Economic Conditions The slower U.S. economy, and the global economy to a lesser extent, may have a significant impact on
Xcel Energy’s operating results. Current economic conditions have resulted in a decline in the forward price curve for energy and
decreased commodity-trading margins. In addition, certain operating costs, such as insurance and security, have increased due to the
economy, terrorist activity and war. Management cannot predict the impact of a continued economic slowdown, fluctuating energy
prices or war. However, Xcel Energy could experience a material adverse impact to its results of operations, future growth or ability to
raise capital due to a weakened economy or war.

Sales Growth In addition to weather impacts, 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 1.8 percent in 2002 compared with 2001, and 1.0 percent in 2001 compared with 2000. Weather-normalized sales growth for firm
natural gas utility customers was estimated to be approximately the same in 2002 compared with 2001, and 2.6 percent in 2001 compared
with 2000. We are projecting that 2003 weather-normalized sales growth in 2003 compared with 2002 will be 1.5 to 2.0 percent for
retail electric utility customers and 2.5 to 3.0 percent for firm natural 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 over the past few years has been significant as utilities combine to capture economies of scale or establish a strategic niche in
preparing for the future. Some regulated utilities are divesting generation assets. All utilities are required to provide nondiscriminatory
access to the use of their transmission systems.

In December 2001, the FERC approved Midwest Independent Transmission System Operator, Inc. (MISO) as the Midwest independent
system operator responsible for operating the wholesale electric transmission system. Accordingly, in compliance with the FERC’s
Order No. 2000, Xcel Energy turned over operational control of its transmission system to the MISO in January 2002.

Some states had begun to allow retail customers to choose their electricity supplier, and many other states were considering retail access
proposals. However, the experience of the state of California in instituting competition, as well as the bankruptcy filing of Enron, have
caused indefinite delays in most industry restructuring.

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 Xcel Energy’s financial position, results of operations and cash flows.

California Power Market NRG operates in the wholesale power market in California. See Note 18 to the Consolidated Financial
Statements for a description of lawsuits against NRG and other power producers and marketers involving the California electricity
markets. Xcel Energy and NRG have fully reserved for their uncollected receivables related to the California power market.

Critical Accounting Policies Preparation of the Consolidated Financial Statements and related disclosures in compliance with generally
accepted accounting principles (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 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 likelihood of resulting in materially different reported
amounts under different conditions or using different assumptions.

page 24

xcel energy inc. and subsidiaries

management ’s discussion and analysis

Accounting Policy

Asset Valuation

NRG
Seren
Argentina

NRG Financial
Restructuring

Judgments/Uncertainties Affecting Application

See Additional Discussion At

– Regional economic conditions affecting asset 

operation, market prices and related cash flows

– Foreign currency valuation changes
– Regulatory and political environments and 

requirements

– Levels of future market penetration and customer

growth

Management’s Discussion and Analysis:
Results of Operations 
Management’s Discussion and Analysis:
Factors Affecting Results of Operations 

Impacts of NRG Financial Difficulties
Impact of Other Nonregulated Investments

Notes to Consolidated Financial Statements

Notes 2, 3 and 18

– Terms negotiated to settle NRG’s obligations to 

its creditors

– Ownership interest in and control of NRG and 
related ability to continue consolidating NRG as 
a subsidiary

Management’s Discussion and Analysis:
Liquidity and Capital Resources

NRG Financial Issues
Xcel Energy Impacts

Notes to Consolidated Financial Statements

– Impacts of court decisions in future bankruptcy

Notes 4 and 18

proceedings, including any obligations of Xcel Energy

Income Tax Accruals

– Application of tax statutes and regulations to 

transactions

– Anticipated future decisions of tax authorities
– Ability of tax authority decisions/positions to 

Management’s Discussion and Analysis:
Factors Affecting Results of Operations 

Tax Matters

Notes to Consolidated Financial Statements

withstand legal challenges and appeals

Notes 1, 11 and 18

– Ability to realize tax benefits through carrybacks 
to prior periods or carryovers to future periods

Benefit Plan Accounting

– Future rate of return on pension and other plan
assets, including impacts of any changes to 
investment portfolio composition

– Interest rates used in valuing benefit obligation
– Actuarial period selected to recognize deferred

investment gains and losses

Management’s Discussion and Analysis:
Factors Affecting Results of Operations 
Pension Plan Costs and Assumptions
Notes to Consolidated Financial Statements

Notes 1 and 13

Regulatory Mechanisms 
and Cost Recovery

– External regulator decisions, requirements and 

regulatory environment

Management’s Discussion and Analysis:
Factors Affecting Results of Operations 

– Anticipated future regulatory decisions and their

Utility Industry Changes and Restructuring 

impact

Notes to Consolidated Financial Statements

– Impact of deregulation and competition on 

Notes 1, 18 and 20 

ratemaking process and ability to recover costs

Environmental Issues

– Approved methods for cleanup
– Responsible party determination
– Governmental regulations and standards
– Results of ongoing research and development 

Management’s Discussion and Analysis:
Factors Affecting Results of Operations 

Environmental Matters

Notes to Consolidated Financial Statements

regarding environmental impacts

Notes 1 and 18

Uncollectible Receivables

– Economic conditions affecting customers, suppliers

and market prices

Management’s Discussion and Analysis:
Factors Affecting Results of Operations 

– Regulatory environment and impact of cost recovery

California Power Market

constraints on customer financial condition

Notes to Consolidated Financial Statements

– Outcome of litigation and regulatory proceedings

Notes 1 and 18

Nuclear Plant 
Decommissioning and 
Cost Recovery

– Costs of future decommissioning
– Availability of facilities for waste disposal
– Approved methods for waste disposal
– Useful lives of nuclear power plants
– Future recovery of plant investment and 

decommissioning costs

Notes to Consolidated Financial Statements

Notes 1, 18 and 19 

xcel energy inc. and subsidiaries          page 25

management ’s discussion and analysis

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 13 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 and decreases in interest rates used to discount benefit obligations. Investment returns in 2000
and 2001 were below the assumed level of 9.5 percent, and interest rates have declined from the 7.5-percent to 8-percent levels used in
1999 and 2000 cost determinations to 7.25 percent used in 2002. Xcel Energy continually reviews its pension assumptions, and in 2003,
expects to change the investment return assumption to 9.25 percent and the discount rate assumption to 6.75 percent.

Xcel Energy bases its investment return assumption on expected long-term performance for each of the investment types included in its
pension asset portfolio. These include equity investments, such as corporate common stocks; fixed-income investments, such as corporate
bonds; and U.S. Treasury securities and nontraditional investments, such as timber or real estate partnerships. In reaching a return
assumption, Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as
well as the long-term return levels projected and recommended by investment experts in the marketplace. The historical weighted average
annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 12.6 percent, in excess of the current assumption
level. The pension cost determinations assume the continued current mix of investment types over the long term. The target and 2002
mix of assets among these portfolio components is discussed in Note 13 to the Consolidated Financial Statements. The Xcel Energy
portfolio is heavily weighted toward equity securities, and includes nontraditional investments that can provide a higher-than-average
return. However, as is the experience in recent years, a higher weighting in equity investments can increase the volatility in the return
levels actually achieved by pension assets in any year. Xcel Energy lowered the 2003 pension investment return assumptions to reflect
the changing expectations of investment experts in the marketplace.

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 9.25 percent in each future year and holding other assumptions constant, we
currently project that the pension costs recognized by Xcel Energy for financial reporting purposes will increase from a credit, or negative
expense, of $84 million in 2002 to a credit of $45 million in 2003, a credit of $20 million in 2004, and a net expense of $20 million
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, 2002, the annualized Moody’s Aa index rate, roughly in the middle of the AAA and BAA range, was 6.63 percent,
which when rounded to the nearest quarter-percent rate, as is our policy, resulted in our 6.75-percent pension discount rate at year-end 2002.
This rate was used to value the actuarial benefit obligations at that date, and will be used in 2003 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 1-percent higher rate of return, 10.25 percent, would decrease 2003 pension costs by $22 million
– a 1-percent lower rate of return, 8.25 percent, would increase 2003 pension costs by $22 million
– a 1-percent higher discount rate, 7.75 percent, would decrease 2003 pension costs by $8 million
– a 1-percent lower discount rate, 5.75 percent, would increase 2003 pension costs by $12 million

Alternative assumptions would also change the expected future cash funding requirements for the pension plans. Cash funding requirements
can be impacted by changes to actuarial assumptions, actual asset levels and other pertinent 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 2003. Assuming future asset return levels equal the actuarial assumption of
9.25 percent for the years 2003-2005, then under current funding regulations we project that no cash funding would be required for
2004, $35 million in funding would be required for 2005 and $54 million in funding would be required for 2006. Actual performance
can affect these funding requirements significantly. If the actual return level is 0 percent in 2003 and 2004, which assumes a continued
downturn in the financial markets, and 9.25 percent in 2005 then the 2004 cash-funding requirement would still be zero. However, the

page 26

xcel energy inc. and subsidiaries

management ’s discussion and analysis

2005 funding requirement would increase to $60 million, and 2006 funding required would be $70 million. Current funding regulations
are under legislative review in 2003, and if not retained in their current form, could change these funding requirements materially.

Regulation Xcel Energy is a registered holding company under the PUHCA. As a result, 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.

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.

Most of the retail rate schedules 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 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
ICA mechanism that allows for an equal sharing among customers and shareholders of certain fuel and energy costs and certain gains
and losses on trading margins.

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 adverse effect on
Xcel Energy’s results of operations in the period the write-off is recorded.

At Dec. 31, 2002, Xcel Energy reported on its balance sheet regulatory assets of approximately $404 million and regulatory liabilities
of approximately $297 million 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. Xcel Energy currently does not expect to write off any stranded costs unless market price levels
change or cost levels increase above market price levels. See Notes 1 and 20 to the Consolidated Financial Statements for further
discussion of regulatory deferrals.

Merger Rate Agreements As part of the merger approval process, Xcel Energy agreed to reduce its rates in several jurisdictions. The
discussion below summarizes the rate reductions in Colorado, Minnesota, Texas and New Mexico.

As part of the merger approval process in Colorado, PSCo agreed to:

– reduce its retail electric rates by an annual rate of $11 million for the period of August 2000 through July 2002;
– file a combined electric and natural gas rate case in 2002, with new rates effective January 2003;
– cap merger costs associated with the electric operations at $30 million and amortize the merger costs for ratemaking purposes

through 2002;

– extend its ICA mechanism through Dec. 31, 2002, with an increase in the ICA base rate from $12.78 per megawatt-hour to a rate

based on 2001 actual costs;

– continue the electric performance-based regulatory plan (PBRP) and the electric quality service plan (QSP) currently in effect through
2006, with modifications to cap electric earnings at a 10.5-percent return on equity for 2002, to reflect no earnings sharing in 2003
since new base rates would have recently been established, and to increase potential bill credits if quality standards are not met; and

– develop a QSP for the natural gas operations to be effective for calendar years 2002 through 2007.

As part of the merger approval process in Minnesota, NSP-Minnesota agreed to:
– reduce its Minnesota electric rates by $10 million annually through 2005;
– not increase its electric rates through 2005, except under limited circumstances;
– not seek recovery of certain merger costs from customers; and
– meet various quality standards.

xcel energy inc. and subsidiaries          page 27

management ’s discussion and analysis

As part of the merger approval process in Texas, SPS agreed to:

– guarantee annual merger savings credits of approximately $4.8 million and amortize merger costs through 2005;
– retain the current fuel-recovery mechanism to pass along fuel-cost savings to retail customers; and
– comply with various service quality and reliability standards, covering service installations and upgrades, light replacements,

customer service call centers and electric service reliability.

As part of the merger approval process in New Mexico, SPS agreed to:

– guarantee annual merger savings credits of approximately $780,000 and amortize merger costs through December 2004;
– share net non-fuel operating and maintenance savings equally among retail customers and shareholders;
– retain the current fuel recovery mechanism to pass along fuel cost savings to retail customers; and
– not pass along any negative rate impacts of the merger.

PSCo Performance-Based Regulatory Plan The Colorado Public Utilities Commission (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 10.5-percent return on equity for 2002;
– no earnings sharing for 2003; and
– an annual electric earnings test with the sharing of earnings in excess of the return on equity set in the 2002 rate case for 2004

through 2006;

– an electric 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;

– 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; and

– an ICA that provides for the sharing of energy costs and savings relative to an annual baseline cost per kilowatt-hour generated or
purchased. According to the terms of the merger rate agreement in Colorado, the annual baseline cost will be reset in 2002, based
on a 2001 test year. Pursuant to a stipulation approved by the CPUC, the ICA remains in effect through March 31, 2005, to recover
allowed ICA costs from 2001 and 2002. The recovery of fuel and purchased energy expense that began Jan. 1, 2003, will be decided
in the PSCo 2002 general rate case. In the interim period until the conclusion of the general rate case, 2003 fuel and purchased
energy expense is recovered through the interim adjustment clause (IAC).

PSCo regularly monitors and records as necessary an estimated customer refund obligation under the earnings test. 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. During 2002, PSCo filed that its electric department earnings were below the 11-percent
return-on-equity threshold. PSCo has estimated no customer refund obligation for 2002 under the earnings test, the electric QSP or the
natural gas QSP. PSCo has estimated no customer refund obligation for 2001 under the earnings test. The 2001 earnings test filing has
not been approved. A hearing is scheduled for May 2003.

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 to address increased costs for providing services to Colorado customers. This filing was required as part of the Xcel
Energy merger stipulation and agreement previously approved by the CPUC. Among other things, the case includes establishing an
electric energy recovery mechanism, elimination of the qualifying facilities capacity cost adjustment (QFCCA), new depreciation
rates and recovery of additional plant investment. PSCo requested an increase to its authorized rate of return on equity to 12 percent for
electricity and 12.25 percent for natural gas. In early 2003, PSCo filed its rebuttal testimony in this rate case. At this point in the
rate proceeding, PSCo is now requesting an overall annual increase to electric revenue of approximately $233 million. This is based
on a $186-million increase for fuel and purchased energy expense and a $47-million electric base rate increase. PSCo is requesting an
annual base rate decrease in natural gas revenue of approximately $21 million. The rebuttal case incorporates several adjustments to the
original filing, including lower depreciation expense, higher fuel and energy expense and various corrections to the original filing.

Intervenors, including the CPUC staff and the Colorado Office of Consumer Council (OCC), have filed testimony requesting
both electric and natural gas base rate decreases and increases in fuel and energy revenues that are less than the amounts requested
by PSCo. On Feb. 19, 2003, the CPUC postponed the scheduled hearings for 30 days to allow parties to pursue a comprehensive
settlement of all issues in this proceeding. PSCo filed a joint motion on March 14, 2003, extending the filing date of the settlement
agreement until April 1, 2003. New rates are expected to be effective during the second quarter of 2003. A final decision on the
recovery of fuel and energy costs will be applied retroactive to Jan. 1, 2003. Until such time, PSCo is billing customers under the
IAC, assuming 100-percent pass-through cost recovery.

Tax Matters As discussed further in Note 18, 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

page 28

xcel energy inc. and subsidiaries

management ’s discussion and analysis

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. After consultation with tax counsel, it is Xcel Energy’s
position that the tax law does not support the IRS determination. Although the ultimate resolution of this matter is uncertain,
management continues to believe it will successfully resolve this matter without a material adverse impact on Xcel Energy’s results of
operations. However, defense of PSCo’s position may require significant cash outlays on a temporary basis, if refund litigation is
pursued in U.S. District Court.

The total disallowance of interest expense deductions for the period of 1993 through 1997 is approximately $175 million. Additional
interest expense deductions for the period 1998 through 2002 are estimated to total approximately $317 million. Should the IRS
ultimately prevail on this issue, tax and interest payable through Dec. 31, 2002, would reduce earnings by an estimated $214 million,
after tax. If COLI interest expense deductions were no longer available, annual earnings for 2003 would be reduced by an estimated
$33 million, after tax, prospectively, which represents 8 cents per share using 2003 share levels.

Environmental Matters Our 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.

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

– $149 million in 2002
– $146 million in 2001
– $144 million in 2000

We expect to expense an average of approximately $177 million per year from 2003 through 2007 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 our regulated facilities, which include the cost of constructing spent nuclear fuel
storage casks, were approximately:

– $108 million in 2002
– $136 million in 2001
– $57 million in 2000

Our regulated utilities expect to incur approximately $44 million in capital expenditures for compliance with environmental regulations
in 2003 and approximately $948 million during the period from 2003 through 2007. Most of the costs are related to modifications to
reduce the emissions of NSP-Minnesota’s generating plants located in the Minneapolis-St. Paul metropolitan area. See Notes 18 and 19
to the Consolidated Financial Statements for further discussion of our environmental contingencies.

NRG expects to incur as much as $145 million in capital expenditures over the next five years to address conditions that existed when it
acquired facilities, and to comply with new regulations.

Impact of Other Nonregulated Investments Xcel Energy’s investments in nonregulated operations have had a significant impact on its
results of operations. Xcel Energy does not expect to continue investing in nonregulated domestic and international power production
projects through NRG, but may continue investing in natural gas marketing and trading through e prime and construction projects
through Utility Engineering. Xcel Energy’s nonregulated businesses may carry a higher level of risk than its traditional utility businesses
due to a number of factors, including:

– competition, operating risks, dependence on certain suppliers and customers, and domestic and foreign environmental and

energy regulations;

– partnership and government actions and foreign government, political, economic and currency risks; and
– development risks, including uncertainties prior to final legal closing.

Xcel Energy’s earnings from nonregulated subsidiaries, other than NRG, also include investments in international projects, primarily in
Argentina, through Xcel Energy International, and broadband communications systems through Seren. Management currently intends
to hold and operate these investments, but is evaluating their strategic fit in Xcel Energy’s business portfolio. As of Dec. 31, 2002, Xcel
Energy’s investment in Seren was approximately $255 million. Seren had capitalized $290 million for plant in service and had incurred
another $21 million for construction work in progress for these systems at Dec. 31, 2002. Xcel Energy International’s gross investment
in Argentina, excluding unrealized currency translation losses of approximately $62 million, was $112 million at Dec. 31, 2002. Given the
political and economic climate in Argentina, Xcel Energy continues to closely monitor the investment for asset impairment. Currently,
management believes that no impairment exists in addition to what was recognized in 2002, as previously discussed.

xcel energy inc. and subsidiaries          page 29

management ’s discussion and analysis

Some of Xcel Energy’s nonregulated subsidiaries have project investments, as listed in Note 14 to the Consolidated Financial Statements,
consisting of minority interests, which may limit the financial risk, but also limit the ability to control the development or operation of
the projects. In addition, significant expenses may be incurred for projects pursued by Xcel Energy’s subsidiaries that do not materialize.
The aggregate effect of these factors creates the potential for volatility in the nonregulated component of Xcel Energy’s earnings.
Accordingly, the historical operating results of Xcel Energy’s nonregulated businesses may not necessarily be indicative of future
operating results.

Inflation Inflation at its current level is not expected to materially affect Xcel Energy’s prices or returns to shareholders. Since late
2001, the Argentine peso has been significantly devalued due to the inflationary Argentine economy. Xcel Energy will continue to
experience related currency translation adjustments through Xcel Energy International.

pending accounting changes 

SFAS No. 143 In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143 – “Accounting for Asset
Retirement Obligations.” This statement will require Xcel Energy to record its future nuclear plant decommissioning obligations as a
liability at fair value with a corresponding increase to the carrying value of the related long-lived asset. The liability will be increased to its
present value each period, and the capitalized cost will be depreciated over the useful life of the related long-lived asset. If at the end of the
asset’s life the recorded liability differs from the actual obligations paid, SFAS No. 143 requires that a gain or loss be recognized at that
time. However, rate-regulated entities may recognize a regulatory asset or liability instead, if the criteria for SFAS No. 71 – “Accounting
for the Effects of Certain Types of Regulation” are met.

Xcel Energy currently follows industry practice by ratably accruing the costs for decommissioning over the approved cost-recovery period
and including the accruals in accumulated depreciation. At Dec. 31, 2002, Xcel Energy recorded and recovered in rates $662 million of
decommissioning obligations and had estimated discounted decommissioning cost obligations of $1.1 billion based on approvals from the
various state commissions, which used a single scenario. However, with the adoption of SFAS No. 143, a probabilistic view of several
decommissioning scenarios was used, resulting in an estimated discounted decommissioning cost obligation of $1.6 billion.

Xcel Energy expects to adopt SFAS No. 143 as required on Jan. 1, 2003. In current estimates for adoption, the initial value of the liability,
including cumulative accretion expense through that date, would be approximately $869 million. This liability would be established by
reclassifying accumulated depreciation of $573 million and by recording two long-term assets totaling $296 million. A gross capitalized
asset of $130 million would be recorded and would be offset by accumulated depreciation of $89 million. In addition, a regulatory asset of
approximately $166 million would be recorded for the cumulative effect adjustment related to unrecognized depreciation and accretion
under the new standard. Management expects that the entire transition amount would be recoverable in rates over time and, therefore,
would support this regulatory asset upon adoption of SFAS No. 143.

Xcel Energy has completed a detailed assessment of the specific applicability and implications of SFAS No. 143 for obligations other
than nuclear decommissioning. Other assets that may have potential asset retirement obligations include ash ponds, any generating
plant with a Part 30 license and electric and natural gas transmission and distribution assets on property under easement agreements.
Easements are generally perpetual and require retirement action only upon abandonment or cessation of use of the property for the
specified purpose. The liability is not estimable because Xcel Energy intends to utilize these properties indefinitely. The asset retirement
obligations for the ash ponds and generating plants cannot be reasonably estimated due to an indeterminate life for the assets associated
with the ponds and uncertain retirement dates for the generating plants. Since the time period for retirement is unknown, no liability
would be recorded. When a retirement date is certain, a liability will be recorded.

SFAS No. 143 also will affect Xcel Energy’s accrued plant removal costs for other generation, transmission and distribution facilities for
its utility subsidiaries. Although SFAS No. 143 does not recognize the future accrual of removal costs as a GAAP liability, long-standing
ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical
depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate
regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates over time, Xcel Energy has
estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing
depreciation rates. Accordingly, Xcel Energy has an estimated regulatory liability accrued in accumulated depreciation for future removal
costs of the following amounts at Dec. 31:

(Millions of dollars)

NSP-Minnesota
NSP-Wisconsin
PSCo
SPS
Cheyenne
Total Xcel Energy

page 30

xcel energy inc. and subsidiaries

2002

$304
70
329
97
9
$ 809

management ’s discussion and analysis

SFAS No. 145 In April 2002, the FASB issued SFAS No. 145 – “Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statement No. 13, and Technical Corrections,” which supercedes previous guidance for the reporting of gains and losses from
extinguishment of debt and accounting for leases, among other things. Adoption of SFAS No. 145 may affect the recognition of
impacts from NRG’s financial improvement and restructuring plan, if existing debt agreements are ultimately renegotiated while NRG
is still a consolidated subsidiary of Xcel Energy. Other impacts of SFAS No. 145 are not expected to be material to Xcel Energy.

SFAS No. 146 In June 2002, the FASB issued SFAS No. 146 – “Accounting for Exit or Disposal Activities,” addressing recognition,
measurement and reporting of costs associated with exit and disposal activities, including restructuring activities. SFAS No. 146 may have
an impact on the timing of recognition of costs related to the implementation of the NRG financial improvement and restructuring plan;
however, such impact is not expected to be material.

SFAS No. 148 In December 2002, the FASB issued SFAS No. 148 – “Accounting for Stock-Based Compensation – Transition and
Disclosure,” amending FASB Statement No. 123 to provide alternative methods of transition for a voluntary change to the fair-value-based
method of accounting for stock-based employee compensation, and requiring disclosure in both annual and interim Consolidated Financial
Statements about the method used and the effect of the method used on results. Xcel Energy continues to account for its stock-based
compensation plans under Accounting Principles Board (APB) Opinion No. 25 - “Accounting for Stock Issued to Employees” and does
not plan at this time to adopt the voluntary provisions of SFAS No. 148.

Emerging Issues Tax Force (EITF) Nos. 02-03 and 98-10 See Note 1 to the Consolidated Financial Statements regarding reporting changes
made in 2002 for the presentation of trading results and pending changes related to accounting for the impacts of trading operations in 2003.

FASB Interpretation No. 45 (FIN No. 45) In November 2002, the FASB issued FIN No. 45 – “Guarantor’s Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” The initial recognition and measurement
provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after Dec. 31, 2002, irrespective
of the guarantor’s fiscal year-end. The disclosure requirements are effective for financial statements of interim or annual periods ending
after Dec. 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements
about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a
guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

FASB Interpretation No. 46 (FIN No. 46) In January 2003, the 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, that requirement has been
applied to subsidiaries in which an enterprise has a majority voting interest, but in many circumstances the enterprise’s consolidated
financial statements do not include the consolidations of variable interest entities with which it has similar relationships but no majority
voting interest. Under FIN No. 46, the voting interest approach is not effective in identifying controlling financial interest. As a result,
Xcel Energy expects that it will have to consolidate its affordable housing investments made through Eloigne, which currently are accounted
for under the equity method.

As of Dec. 31, 2002, the assets of these entities were approximately $155 million and long-term liabilities were approximately $87 million.
Currently, investments of $62 million are reflected as a component of investments in unconsolidated affiliates in the Dec. 31, 2002,
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, then 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 the 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. Had Xcel Energy adopted FIN No. 46 requirements
early in 2002, there would have been no material impact to net income. Xcel Energy plans to adopt FIN No. 46 when required in the
third quarter of 2003.

derivatives, risk management and market risk

Business and Operational Risk Xcel Energy and its subsidiaries 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 have limited exposure 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.

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 we use various physical contracts and derivative instruments to reduce the cost of 

xcel energy inc. and subsidiaries          page 31

management ’s discussion and analysis

natural gas and electricity we provide to our 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 are 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. Xcel Energy manages this market price
risk by entering into firm power sales agreements for approximately 55 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, we manage 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 the company to manage market
price risks, and provides guidelines for the level of price risk exposure that is acceptable within the company’s operations.

Xcel Energy is exposed to market price risk for the sale of electric energy and the purchase of fuel resources used to generate the electric
energy from the company’s equity method investments that own electric operations. Xcel Energy manages this market price risk through
involvement with the management committee or board of directors of each of these ventures. Xcel Energy’s risk management policy
does not cover the activities conducted by the ventures. However, other policies are adopted by the ventures as necessary and mandated
by the equity owners.

Interest Rate Risk Xcel Energy and its subsidiaries are exposed to fluctuations in interest rates when entering into variable rate debt
obligations to fund certain power projects being developed or purchased. Exposure to interest rate fluctuations may be mitigated by
entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to
the volatility of cash flows for interest and result in primarily fixed-rate debt obligations when taking into account the combination of
the variable rate debt and the interest rate derivative instrument. Xcel Energy’s risk management policy allows the company to reduce
interest rate exposure from variable-rate debt obligations.

At Dec. 31, 2002 and 2001, a 100-basis point change in the benchmark rate on Xcel Energy’s variable debt would impact net income
by approximately $52.2 million and $29.9 million, respectively. See Note 16 to the Consolidated Financial Statements for a discussion
of Xcel Energy and its subsidiaries’ interest rate swaps.

Currency Exchange Risk Xcel Energy and its subsidiaries have certain investments in foreign countries, creating exposure to foreign
currency exchange risk. The foreign currency exchange risk includes the risk relative to the recovery of our net investment in a project,
as well as the risk relative to the earnings and cash flows generated from such operations. Xcel Energy manages 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.

As discussed in Note 21 to the Consolidated Financial Statements, Xcel Energy has substantial investments in foreign projects, through
NRG and other subsidiaries, creating exposure to currency translation risk. Cumulative translation adjustments, included in the
Consolidated Statement of Stockholders’ Equity as Accumulated Other Comprehensive Income, experienced to date have been material
and may continue to occur at levels significant to the company’s financial position. As of Dec. 31, 2002, NRG had two foreign currency
exchange contracts with notional amounts of $3 million. If the contracts had been discontinued on Dec. 31, 2002, NRG would have
owed the counterparties approximately $0.3 million.

Trading Risk Xcel Energy and its subsidiaries conduct various trading operations and power marketing activities, including the purchase
and sale of electric capacity and energy and natural gas. The trading operations are conducted both in the United States and Europe 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.

The fair value of Xcel Energy’s trading contracts as of Dec. 31, 2002, is as follows:

(Millions of dollars)

Fair value of trading contracts outstanding at Jan. 1, 2002
Contracts realized or settled during 2002
Fair value of trading contract additions and changes during the year
Fair value of contracts outstanding at Dec. 31, 2002*

* Amounts do not include the impact of ratepayer sharing in Colorado.

Total Fair Value

$  90.1
(139.5)
87.8
$  38.4

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xcel energy inc. and subsidiaries

management ’s discussion and analysis

The future maturities of Xcel Energy’s trading contracts are as follows:

(Millions of dollars)
Source of fair value

Prices actively quoted
Prices based on models and other valuation methods 
(including prices quoted from external sources)

Maturity
Less than 
1 Year

Maturity 
1 to 3 Years

Maturity
Maturity Greater than 
5 Years

4 to 5 Years

Total
Fair Value

$12.7

$ (7.1)

$

–

$ (1.9)

$ 3.7

$61.7

$52.6

$(23.0)

$(56.6)

$34.7

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 and various holding periods varying from two to five days.

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

(Millions of dollars)

Electric commodity trading
Natural gas commodity trading
Natural gas retail marketing
NRG power marketing (a)

(a) NRG VaR is an undiversified VaR.

As of Dec. 31, 2001, the calculated VaRs were:

(Millions of dollars)

Electric commodity trading
Natural gas commodity trading
Natural gas retail marketing
NRG power marketing

Year Ended
Dec. 31, 2002

0.29
0.11
0.54
118.60

Year Ended
Dec. 31, 2001

0.52
0.16
0.69
71.70

Average

0.62
0.35
0.47
76.20

Average

1.71
0.15
0.39
78.80

During 2002
High

3.39
1.09
0.92
124.40

During 2001
High

7.37
0.52
0.94
126.60

Low

0.01
0.09
0.32
42.00

Low 

0.16
0.01
0.13
58.60

In 2001, Xcel Energy changed its holding period for measuring VaR from electricity trading activity from 21 days to two to five days.
Xcel Energy’s revised holding periods are generally consistent with current industry standard practice.

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. As Xcel Energy continues to expand its natural gas and power marketing and trading activities, exposure to credit risk and
counterparty default may increase. 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.

liquidity and capital resources

cash flows
(Millions of dollars)

Net cash provided by operating activities

2002

$1,715

2001

$1,584

2000

$1,408

xcel energy inc. and subsidiaries          page 33

management ’s discussion and analysis

Cash provided by operating activities 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. In addition, regulated utility operating cash flows increased in 2002 due
to lower 2002 receivables and unbilled revenues, reflecting collections of higher year-end 2001 amounts. Cash provided by operating
activities increased during 2001, compared with 2000, primarily due to higher net income, depreciation and improved working capital.

(Millions of dollars)

Net cash used in investing activities

2002

2001

2000

$(2,718)

$(5,168)

$(3,347)

Cash used in investing activities 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 used in investing activities
increased during 2001, compared with 2000, primarily due to increased levels of nonregulated capital expenditures and asset acquisitions,
primarily at NRG. The increase was partially offset by Xcel Energy’s sale of most of its investment in Yorkshire Power.

(Millions of dollars)

Net cash provided by financing activities

2002

2001

2000

$ 1,580

$ 3,713

$ 2,016

Cash provided by financing activities 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. Cash provided by financing activities increased during
2001, compared with 2000, primarily due to increased short-term borrowings and net long-term debt issuances, mainly to fund
NRG acquisitions.

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 NRG, and other capital requirements for the years 2003, 2004 and 2005 are
shown in the table below.

(Millions of dollars)

Electric utility
Natural gas utility
Common utility
Total utility

Other nonregulated (excluding NRG)

Total capital expenditures
Sinking funds and debt maturities
Total capital requirements

2003

$

700
110
90
900
32
932
563
$ 1,495

2004

$

840
110
50
1,000
23
1,023
169
$ 1,192

2005

$

950
110
40
1,100
15
1,115
223
$ 1,338

The capital expenditure forecast for 2004 includes new steam generators at the Prairie Island nuclear plant. These expenditures will not
occur unless the Minnesota Legislature grants additional spent fuel storage at Prairie Island during 2003. The capital expenditure forecast
also includes the early stages of the costs related to modifications to reduce the emissions of NSP-Minnesota’s generating plants located
in the Minneapolis and St. Paul metropolitan area. This project is expected to cost approximately $1.1 billion with major construction
starting in 2005 and finishing in 2009.

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 merger, acquisition and divestiture opportunities to support corporate strategies, address restructuring requirements and
comply with future requirements to install emission-control equipment may impact actual capital requirements. For more information,
see Notes 4 and 18 to the Consolidated Financial Statements.

Xcel Energy’s investment in exempt wholesale generators and foreign utility companies, which includes NRG and other Xcel Energy
subsidiaries, is currently limited to 100 percent of consolidated retained earnings, as a result of the PUHCA restrictions. At Dec. 31, 2002,
such investments exceeded consolidated retained earnings.

NRG Energy is required to provide financial guarantees of up to approximately $8 million for closure and ongoing monitoring costs
of some sites to which it sends coal ash and other waste, by April 30, 2003.

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xcel energy inc. and subsidiaries

management ’s discussion and analysis

NRG Capital Expenditures Management expects NRG’s capital expenditures, which include refurbishments and environmental
compliance, to total approximately $475 million to $525 million in the years 2003 through 2007. NRG anticipates funding its
ongoing capital requirements through committed debt facilities, operating cash flows and existing cash. NRG’s capital expenditure
program is subject to continuing review and modification. The timing and actual amount of expenditures may differ significantly
based upon plant operating history, unexpected plant outages, changes in the regulatory environment and the availability of cash.
The pending financial restructuring or bankruptcy filings of NRG may affect the timing and magnitude of capital resources available
to NRG and, accordingly, the level of capital expenditures NRG can fund.

Contractual Obligations and Other Commitments Xcel Energy has a variety of contractual obligations and other commercial commitments
that represent prospective requirements in addition to its capital expenditure programs. The following is a summarized table of contractual
obligations. See additional discussion in the Consolidated Statements of Capitalization and Notes 5, 6, 7, 16 and 18 to the Consolidated
Financial Statements.

(Thousands of dollars)
Contractual obligations

Long-term debt
Capital lease obligations
Operating leases(a)
Unconditional purchase obligations
Other long-term obligations
Short-term debt

Total contractual cash obligations

Total

Less than 1 Year

1–3 Years

4–5 Years After 5 Years

Payments Due by Period

$14,311,689
688,421
386,215
11,240,364
699,248
1,541,963
$28,867,900

$  7,756,903
34,422
66,155
1,317,293
42,597
1,541,963
$10,759,333

$ 547,796
67,771
125,031
2,214,974
64,517
–
$3,020,089

$1,137,934 $ 4,869,056
519,842
86,495
5,890,327
557,540
–
$3,165,218 $11,923,260

66,386
108,534
1,817,770
34,594
–

(a) Under some leases, we would have to sell or purchase the property that we lease if we chose to terminate before the scheduled lease expiration date. Most of our railcar,
vehicle and equipment, and aircraft leases have these terms. We would then own the equipment and could continue to use it in the normal course of business or sell it.
At Dec. 31, 2002, the amount that we would have to pay if we chose to terminate these leases was approximately $160 million.

Common Stock Dividends Future dividend levels will be dependent upon the statutory limitations discussed further, 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.

Under the 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. Due to 2002 losses incurred by NRG, retained earnings of Xcel Energy were a deficit of $101 million at Dec. 31, 2002.
Xcel Energy did not declare a dividend on its common stock during the first quarter of 2003. Xcel Energy has requested authorization from
the SEC to pay dividends out of paid-in capital up to $260 million until Sept. 30, 2003. It is not known when or if the SEC will act on this
request. As explained below, Xcel Energy has reached a preliminary settlement agreement with the various NRG creditors. Also, Xcel Energy
could be required to cease including NRG as a consolidated subsidiary for financial reporting purposes, if NRG were to seek protection
under the bankruptcy laws and Xcel Energy ceased to have control over NRG. In the event the tentative settlement is effectuated and
Xcel Energy is required to cease including NRG as a consolidated subsidiary in its financial statements, the financial impact of these
events are expected to positively impact retained earnings and may be sufficient to eliminate the negative retained earnings balance, absent
additional charges at NRG. Xcel Energy cannot predict the precise financial impact of these items at this time. For this reason, Xcel
Energy will continue seeking authorization from the SEC so it is able to pay dividends notwithstanding negative retained earnings.
Xcel Energy intends to make every effort to pay the full common stock dividend of 75 cents per share during 2003.

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 (i) common stock
plus surplus divided by (ii) the sum of common stock plus surplus plus long-term debt. Based on this definition, our capitalization ratio
at Dec. 31, 2002, was 85 percent. Therefore, the restrictions do not place any effective limit on our 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 our common stock.

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. As a result of its registration as a holding company under the PUHCA, Xcel
Energy is required to maintain a common equity ratio of 30 percent or higher in its consolidated capital structure.

On Nov. 7, 2002, the SEC issued an order authorizing Xcel Energy to engage in certain financing transactions through March 31, 2003,
so long as its common equity ratio, as reported in its most recent Form 10-K or Form 10-Q and as adjusted for pending subsequent
items that affect capitalization, was at least 24 percent of its total capitalization. Financings of Xcel Energy authorized by the SEC
included the issuance of debt, including convertible debt, to refinance or replace Xcel Energy’s $400-million credit facility that expired
on Nov. 8, 2002, issuance of $450 million of common stock, less any amounts issued as part of the refinancing of the $400-million

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management ’s discussion and analysis

credit facility, and the renewal of guarantees for various trading obligations of NRG’s power marketing subsidiary. The SEC reserved
authorizing additional securities issuances by Xcel Energy through June 30, 2003, while its common equity ratio is below 30 percent.

For this purpose, common equity, including minority interest, at Dec. 31, 2002, was 23 percent of total capitalization. As a result,
Xcel Energy may experience constraints on available capital sources that may be affected by factors including earnings levels, project
acquisitions and the financing actions of our subsidiaries. In the event that NRG were to seek protection under bankruptcy laws and
Xcel Energy ceased to have control over NRG, NRG would no longer be a consolidated subsidiary of Xcel Energy for financial
reporting purposes, and Xcel Energy’s common equity ratio under the SEC’s method of calculation would exceed 30 percent.

In December 2002, Xcel Energy filed a request for additional financing authorization with the SEC. Xcel Energy requested an increase
from $2 billion to $2.5 billion in the aggregate amount of securities that it may issue during the period through Sept. 30, 2003. In addition,
the request proposed that common equity will be at least 30 percent of total consolidated capitalization, provided that in any event the
30-percent common equity requirement is not met, Xcel Energy may issue common stock. The notice period expired with no comments.
SEC action on the request is pending. As a result, Xcel Energy at the present time cannot finance, either on a short-term or long-term
basis, without SEC approval unless its common equity is at least 30 percent of total capitalization.

With approval of the request currently pending before the SEC, further described below, management believes it will have adequate
authority under SEC orders and regulations to conduct business as proposed during 2003 and will seek additional authorization
when necessary.

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 utility construction expenditures and nonregulated project investments. Another significant
short-term funding need is the dividend payment requirement, as discussed previously in Common Stock Dividends.

Operating cash flow as a source of short-term funding is reasonably likely to be 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 that are difficult to predict. See further discussion of such factors under Statement
of Operations Analysis and Factors Affecting Results of Operations.

Short-term borrowing as a source of funding is affected by regulatory actions and access to reasonably priced capital markets. This varies
based on financial performance and existing debt levels. These factors are evaluated by credit-rating agencies that review Xcel Energy and
its subsidiary operations on an ongoing basis. NRG’s credit situation has affected Xcel Energy’s credit ratings and access to short-term
funding. As a result of a decline in its credit ratings, Xcel Energy has been unable to utilize the commercial paper market to satisfy
any short-term funding needs. 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 also dependent in part on credit agency reviews. In the past year, our credit ratings and
those of our subsidiaries have been adversely affected by NRG’s credit contingencies, despite what management believes is a reasonable
separation of NRG’s operations and credit risk from our utility operations and corporate financing activities. These 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. 10, 2003, the following represents the credit ratings assigned
to various Xcel Energy companies:

Company

Xcel Energy
Xcel Energy
NSP-Minnesota
NSP-Minnesota
NSP-Minnesota
NSP-Wisconsin
NSP-Wisconsin
PSCo
PSCo
PSCo
SPS
SPS
NRG

Credit Type

Moody’s* 

Standard & Poor’s

Senior Unsecured Debt
Commercial Paper
Senior Unsecured Debt
Senior Secured Debt
Commercial Paper
Senior Unsecured Debt
Senior Secured Debt
Senior Unsecured Debt
Senior Secured Debt
Commercial Paper
Senior Unsecured Debt
Commercial Paper
Corporate Credit Rating

Baa3
NP
Baa1
A3
P2
Baa1
A3
Baa2
Baa1
P2
Baa1
P2
Caa3**

BBB-
A3
BBB-
BBB+
A3
BBB
BBB+
BBB-
BBB+
A3
BBB
A3
D **

* Negative credit watch/negative outlook
** Below investment grade

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management ’s discussion and analysis

NRG’s access to short-term capital is currently nonexistent outside of bankruptcy. The downgrade of NRG’s credit ratings below investment
grade in July 2002 has resulted in cash collateral requirements, as discussed previously and in Notes 4 and 7 to the Consolidated Financial
Statements. In addition, lower credit ratings will increase the relative cost of NRG’s capital financing compared with historical levels,
assuming NRG could obtain such financing.

In June 2002, Xcel Energy’s access to commercial paper markets was reduced due to lowered credit ratings, shown previously. Xcel
Energy typically uses sources of financing, both short- and long-term, other than commercial paper to fulfill its cash needs and
manage its capital structure.

NRG Capital Sources NRG has generally financed the acquisition and development of its projects under financing arrangements to be
repaid solely from each of its project’s cash flows, which are typically secured by the plant’s physical assets and equity interests in the
project company. As discussed previously, NRG’s credit situation has significantly affected its credit ratings and virtually eliminated its
access to short-term funding. See credit ratings in previous table. NRG anticipates funding its ongoing capital requirements through
committed debt facilities, operating cash flows and existing cash.

NRG’s operating cash flows have been affected by lower operating margins as a result of low power prices since mid-2001. Seasonal
variations in demand and market volatility in prices are not unusual in the independent power sector, and NRG normally experiences
higher margins in peak summer periods and lower margins in non-peak periods. NRG also has incurred significant amounts of debt to
finance its acquisitions in the past several years, and the servicing of interest and principal repayments from such financing is largely
dependent on domestic project cash flows. Management has concluded that the forecasted free cash flow available to NRG after servicing
project-level obligations will be insufficient to service recourse debt obligations at NRG.

Substantially all of NRG’s operations are conducted by project subsidiaries and project affiliates. NRG’s cash flow and ability to service
corporate-level indebtedness when due is dependent upon receipt of cash dividends and distributions or other transfers from NRG’s
projects and other subsidiaries. NRG has generally financed the acquisition and development of its projects under financing arrangements
to be repaid solely from each of its project’s cash flows, which are typically secured by the plant’s physical assets and equity interests in
the project company. In August 2002, NRG suspended substantially all of its acquisition and development activities indefinitely, pending
a comprehensive restructuring of NRG. The debt agreements of NRG’s subsidiaries and project affiliates generally restrict their ability
to pay dividends, make distributions or otherwise transfer funds to NRG. As of Dec. 31, 2002, Loy Yang, Energy Center Kladno, LSP
Energy (Batesville), NRG South Central and NRG Northeast Generating do not currently meet the minimum debt service coverage
ratios required for these projects to make payments to NRG. In addition, NRG’s subsidiaries, including LSP Kendall, NRG McClain,
NRG Mid-Atlantic, NRG South Central and NRG Northeast Generating are in default on their various debt instruments, resulting in
dividend payment restrictions.

For additional information on NRG’s defaults on short-term and long-term borrowing arrangements, see Note 7 to the Consolidated
Financial Statements.

Registration Statements Xcel Energy’s Articles of Incorporation authorize the issuance of 1 billion shares of common stock. As of
Dec. 31, 2002, 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, 2002, Xcel Energy had
approximately 1 million shares of preferred stock outstanding. Registered securities available for issuance are as follows:

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 registra-
tion, which it can issue only when its common equity exceeds 30 percent of its total capitalization absent SEC approval under PUHCA.

In April 2001, NSP-Minnesota filed a $600-million, long-term debt shelf registration with the SEC. NSP-Minnesota has approximately
$415 million remaining under this registration.

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

In June 2001, NRG filed a shelf registration with the SEC to sell up to $2 billion in debt securities, common and preferred stock,
warrants and other securities. NRG has approximately $1.5 billion remaining under this shelf registration. However, NRG’s access
to capital markets is severely constrained and the registration no longer represents access to financing sources.

In March 2003, PSCo issued $250 million of 4.875-percent, First Collateral Trust Bonds due in 2013. The bonds were issued in a private
placement to qualified institutional buyers and were not registered under the Securities Act of 1933. Pursuant to a registration rights
agreement, PSCo has an obligation to file a registration statement for an exchange offer for these bonds.

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management ’s discussion and analysis

other liquidity and capital resource considerations

NRG Financial Issues and Potential Bankruptcy Historically, NRG has obtained cash from operations, issuance of debt and equity
securities, borrowings under credit facilities, capital contributions from Xcel Energy, reimbursement by Xcel Energy of tax benefits
pursuant to a tax-sharing agreement and proceeds from nonrecourse project financings. NRG has used these funds to finance operations;
service debt obligations; fund the acquisition, development and construction of generation facilities; finance capital expenditures; and meet
other cash and liquidity needs.

As discussed previously, substantially all of NRG’s operations are conducted by project subsidiaries and project affiliates. NRG’s cash
flow and ability to service corporate-level indebtedness when due is dependent upon receipt of cash dividends and distributions or other
transfers from NRG’s projects and other subsidiaries. The debt agreements of NRG’s subsidiaries and project affiliates generally restrict
their ability to pay dividends, make distributions or otherwise transfer funds to NRG. As of Dec. 31, 2002, Loy Yang, Killingholme,
Energy Center Kladno, LSP Energy (Batesville), NRG South Central and NRG Northeast Generating do not currently meet the
minimum debt service coverage ratios required for these projects to make payments to NRG.

Killingholme, NRG South Central and NRG Northeast Generating are in default on their credit agreements. NRG believes the
situations at Energy Center Kladno, Loy Yang and Batesville do not create an event of default and will not allow the lenders to
accelerate the project financings.

In all of these cases, NRG’s corporate-level financial obligations to project lenders is limited to no more than six-months’ debt service.

As discussed previously, NRG’s operating cash flows have been affected by lower operating margins as a result of low power prices
since mid-2001. Seasonal variations in demand and market volatility in prices are not unusual in the independent power sector, and
NRG normally experiences higher margins in peak summer periods and lower margins in non-peak periods. NRG also has incurred
significant amounts of debt to finance its acquisitions in the past several years, and the servicing of interest and principal repayments
from such financing is largely dependent on domestic project cash flows. NRG’s management has concluded that the forecasted free
cash flow available to NRG after servicing project-level obligations will be insufficient to service recourse debt obligations.

Since mid-2002, as discussed previously, NRG has experienced severe financial difficulties, resulting primarily from declining credit ratings
and lower prices for power. These financial difficulties have caused NRG to, among other things, miss several scheduled payments of interest
and principal on its bonds and incur an approximately $3-billion asset impairment charge. The asset impairment charge relates to write-offs
for anticipated losses on sales of several projects as well as anticipated losses for projects for which NRG has stopped funding. In addition,
as a result of having its credit ratings downgraded, NRG is in default of obligations to post cash collateral of approximately $1 billion.
Furthermore, on Nov. 6, 2002, lenders to NRG accelerated approximately $1.1 billion of NRG’s debt under the construction revolver financing
facility, rendering the debt immediately due and payable. In addition, on Feb. 27, 2003, lenders to NRG accelerated approximately $1.0 billion
of NRG Energy’s debt under the corporate revolver financing facility, rendering the debt immediately due and payable. NRG continues to
work with its lenders and bondholders on a comprehensive restructuring plan. NRG does not contemplate making any principal or interest
payments on its corporate-level debt pending the restructuring of its obligations. Consequently, NRG is, and expects to continue to be, in
default under various debt instruments. By reason of these various defaults, the lenders are able to seek to enforce their remedies, if they so
choose, and that would likely lead to a bankruptcy filing by NRG in 2003.

Whether NRG does or does not reach a consensual restructuring plan with its creditors, there is a substantial likelihood that NRG will
be the subject of a bankruptcy proceeding in 2003. If an agreement is reached with NRG’s creditors on a restructuring plan, it is expected
that NRG would as soon as practicable commence a Chapter 11 bankruptcy case and immediately seek approval of a prenegotiated
plan of reorganization. Absent an agreement with NRG’s creditors and the continued forbearance by such creditors, NRG will be
subject to substantial doubt as to its ability to continue as a going concern and will likely be the subject of a voluntary or involuntary
bankruptcy proceeding, which, due to the lack of a prenegotiated plan of reorganization, would be expected to take an extended
period of time to be resolved and may involve claims against Xcel Energy under the equitable doctrine of substantive consolidation,
as discussed following.

In addition to the collateral requirements, NRG must continue to meet its ongoing operational and construction funding requirements.
Since NRG’s credit-rating downgrade, its cost of borrowing has increased and it has not been able to access the capital markets. NRG
believes that its current funding requirements under its already reduced construction program may be unsustainable given its inability to
raise money in the capital markets and the uncertainties involved in obtaining additional equity funding from Xcel Energy. NRG and
Xcel Energy have retained financial advisors to help work through these liquidity issues.

As discussed previously, NRG is not making any payments of principal or interest on its corporate-level debt, and neither NRG nor any
subsidiary is making payment of principal or interest on publicly held bonds. This failure to pay, coupled with past and anticipated
proceeds from the sales of projects, has provided NRG with adequate liquidity to meet its day-to-day operating costs. However, there
can be no assurance that holders of NRG indebtedness, on which interest and principal are not being paid, will not seek to accelerate
the payment of their indebtedness, which would likely lead to NRG seeking relief under the bankruptcy laws.

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management ’s discussion and analysis

At the present time and based on conversations with various lenders, Xcel Energy management believes that the appropriate course is to
seek a consensual restructuring of NRG with its creditors. Following an agreement on the restructuring with NRG’s creditors, as described
in Note 4 to the Consolidated Financial Statements, it is expected that NRG would commence a Chapter 11 bankruptcy proceeding
and immediately seek approval of a prenegotiated plan of reorganization. If a consensual restructuring cannot be reached, the likelihood
of NRG becoming subject to a protracted voluntary or involuntary bankruptcy proceeding is increased. If a consensual restructuring of
NRG cannot be obtained and NRG remains outside of a bankruptcy proceeding, NRG is expected to continue selling assets to reduce
its debt and improve its liquidity. Through Jan. 31, 2003, NRG completed a number of transactions, which resulted in net cash proceeds
to NRG after debt pay-downs and after financial advisor fees of approximately $350 million.

Xcel Energy Impacts During 2002, Xcel Energy provided NRG with $500 million of cash infusions. In May 2002, Xcel Energy and
NRG entered into a support and capital subscription agreement (Support Agreement) pursuant to which Xcel Energy agreed, under
certain circumstances, to provide an additional $300 million to NRG. Xcel Energy has not, to date, provided funds to NRG under this
agreement. See discussion of preliminary settlement with NRG’s creditors at Note 4 to the Consolidated Financial Statements.

Many companies in the regulated utility industry, with which the independent power industry is closely linked, also are restructuring or
reviewing their strategies. Several of these companies are discontinuing going forward with unregulated investments, seeking to divest of
their unregulated subsidiaries or attempting to have their regulated subsidiaries acquire their unregulated subsidiaries. This may lead to
an increased competition between the regulated utilities and the unregulated power producers within certain markets. In such instances,
NRG may compete with regulated utilities in the influence of market designs and rulemaking.

On March 26, 2003, Xcel Energy’s board of directors approved a tentative settlement with holders of most of NRG’s long-term notes
and the steering committee representing NRG’s bank lenders regarding alleged claims of such creditors against Xcel Energy, including
claims related to the Support Agreement. The settlement is subject to a variety of conditions as set forth below, including definitive
documentation. As described in Note 4 to the Consolidated Financial Statements, the settlement would require Xcel Energy to pay up
to $752 million over 13 months. Xcel Energy would expect to fund those payments with cash from tax savings. The principal terms of
the settlement as of the date of this report were as follows:

Xcel Energy would pay up to $752 million to NRG to settle all claims of NRG and the claims of NRG against Xcel Energy, including
all claims under the Support Agreement.

$350 million would be paid at or shortly following the consummation of a restructuring of NRG’s debt through a bankruptcy proceeding.
It is expected that this payment would be made prior to year-end 2003. $50 million would be paid on Jan. 1, 2004, and all or any part of such
payment could be made, at Xcel Energy’s election, in Xcel Energy common stock. Up to $352 million would be paid on April 30, 2004,
except to the extent that Xcel Energy had not received at such time tax refunds equal to $352 million associated with the loss on its
investment in NRG. To the extent Xcel Energy had not received such refunds, the April 30 payment would be due on May 30, 2004.

$390 million of the Xcel Energy payments are contingent on receiving releases from NRG creditors. To the extent Xcel Energy does not
receive a release from an NRG creditor, Xcel Energy’s obligation to make $390 million of the payments would be reduced based on the
amount of the creditor’s claim against NRG. As noted below, however, the entire settlement is contingent upon Xcel Energy receiving
releases from at least 85 percent of the claims in various NRG creditor groups. As a result, it is not expected that Xcel Energy’s payment
obligations would be reduced by more than approximately $60 million. Any reduction would come from the Xcel Energy payment due
on April 30, 2004.

Upon the consummation of NRG’s debt restructuring through a bankruptcy proceeding, Xcel Energy’s exposure on any guarantees or
other credit supported obligations incurred by Xcel Energy for the benefit of NRG or any subsidiary would be terminated, and any cash
collateral posted by Xcel Energy would be returned to it. The current amount of such cash collateral is approximately $11.5 million.

As part of the settlement with Xcel Energy, any intercompany claims of Xcel Energy against NRG or any subsidiary arising from the
provision of intercompany goods or services or the honoring of any guarantee will be paid in full in cash in the ordinary course except
that the agreed amount of such intercompany claims arising or accrued as of Jan. 31, 2003, will be reduced from approximately $55 million as
asserted by Xcel Energy to $13 million. The $13 million agreed amount is to be paid upon the consummation of NRG’s debt restructuring
with $3 million in cash and an unsecured promissory note of NRG on market terms in the principal amount of $10 million.

NRG and its direct and indirect subsidiaries would not be reconsolidated with Xcel Energy or any of its other affiliates for tax purposes
at any time after its June 2002 reaffiliation or treated as a party to or otherwise entitled to the benefits of any tax sharing agreement with
Xcel Energy. Likewise, NRG would not be entitled to any tax benefits associated with the tax loss Xcel Energy expects to incur in
connection with the write-down of its investment in NRG.

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management ’s discussion and analysis

Xcel Energy’s obligations under the tentative settlement, including its obligations to make the payments set for the above, are contingent
upon, among other things, the following:

– definitive documentation, in form and substance satisfactory to the parties;
– between 50 percent and 100 percent of the claims represented by various NRG facilities or creditor groups (NRG Credit Facilities)

having executed an agreement, in form and substance satisfactory to Xcel Energy, to support the settlement;

– various stages of the implementation of the settlement occurring by dates currently being negotiated, with the consummation of

the settlement to occur by Sept. 30, 2003;

– the receipt of releases in favor of Xcel Energy by at least 85 percent of the claims represented by the NRG Credit Facilities;
– the receipt by Xcel Energy of all necessary regulatory approvals; and
– no downgrade prior to consummation of the settlement of any Xcel Energy credit rating from the level of such rating as of March

25, 2003.

Based on the foreseeable effects of a settlement agreement with the major NRG noteholders and bank lenders and the tax effect of an
expected write-off of Xcel Energy’s investment in NRG, Xcel Energy would recognize the expected tax benefits of the write-off as of
Dec. 31, 2002. The tax benefit has been estimated at approximately $706 million. This benefit is based on the tax basis of Xcel Energy’s
investment in NRG.

Xcel Energy expects to claim a worthless stock deduction in 2003 on its investment. This would result in Xcel Energy having a net
operating loss for the year. Under current law, this 2003 net operating loss could be carried back two years for federal purposes. Xcel
Energy expects to file for a tax refund of approximately $355 million in first quarter 2004. This refund is based on a two-year carryback.
However, under the Bush administration’s new dividend tax proposal, the carryback could be one year, which would reduce the refund
to $125 million.

As to the remaining $351 million of expected tax benefits, Xcel Energy expects to eliminate or reduce estimated quarterly income tax
payments, beginning in 2003. The amount of cash freed up by the reduction in estimated tax payments would depend on Xcel Energy’s
taxable income.

While it is an exception rather than the rule, especially where one of the companies involved is not in bankruptcy, the equitable doctrine
of substantive consolidation permits a bankruptcy court to disregard the separateness of related entities, consolidate and pool the entities’
assets and liabilities and treat them as though held and incurred by one entity where the interrelationship between the entities warrants
such consolidation. In the event the settlement described previously is not effectuated, Xcel Energy believes that any effort to substan-
tively consolidate Xcel Energy with NRG would be without merit. However, it is possible that NRG or its creditors would attempt to
advance such claims, or other claims under piercing the corporate veil, alter ego or related theories, should an NRG bankruptcy
proceeding commence, particularly in the absence of a prenegotiated plan of reorganization, and Xcel Energy cannot be certain how a
bankruptcy court would resolve these issues. One of the creditors of the NRG project Pike, as discussed in Note 18 to the
Consolidated Financial Statements, has already filed involuntary bankruptcy proceedings against that project and has included claims
against both NRG and Xcel Energy. Also, as discussed in Note 18 to the Consolidated Financial Statements, a group of former
executives of NRG have commenced an involuntary bankruptcy proceeding against NRG related to the payments of certain benefits
and deferred compensation amounts claimed to be due them. If a bankruptcy court were to allow substantive consolidation of Xcel
Energy and NRG, it would have a material adverse effect on Xcel Energy.

The accompanying Consolidated Financial Statements do not reflect any conditions or matters that would arise if NRG were in bankruptcy.

If NRG were to file for bankruptcy, and the necessary actions were taken by Xcel Energy to fully relinquish its effective control over
NRG, Xcel Energy anticipates that NRG would no longer be included in Xcel Energy’s consolidated financial statements, prospectively
from the date such actions were taken. Such de-consolidation of NRG would encompass a change in Xcel Energy’s accounting for
NRG to the equity method, under which Xcel Energy would continue to record its interest in NRG’s income or losses until Xcel
Energy’s investment in NRG (under the equity method) reached the level of obligations that Xcel Energy had either guaranteed on
behalf of NRG or was otherwise committed to in the form of financial assistance to NRG. Prior to completion of a bankruptcy proceeding,
a prenegotiated plan of reorganization or other settlement reached with NRG’s creditors would be the determining factors in assessing
whether a commitment to provide financial assistance to NRG existed at the time of de-consolidation.

At Dec. 31, 2002, Xcel Energy’s pro forma investment in NRG, calculated under the equity method if applied at that date, was a negative
$625 million. If the amount of guarantees or other financial assistance committed to NRG by Xcel Energy exceeded that level after
de-consolidation of NRG, then NRG’s losses would continue to be included in Xcel Energy’s results until the amount of negative
investment in NRG reaches the amount of guarantees and financial assistance committed to by Xcel Energy. As of Dec. 31, 2002,
the estimated guarantee exposure that Xcel Energy had related to NRG liabilities was $96 million, as discussed in Note 16 to the
Consolidated Financial Statements, and potential financial assistance was committed in the form of a support and capital subscription 

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xcel energy inc. and subsidiaries

management ’s discussion and analysis

agreement pursuant to which Xcel Energy agreed, under certain circumstances, to provide an additional $300 million contribution
to NRG if the financial restructuring plan discussed earlier is approved by NRG’s creditors. Additional commitments for financial
assistance to NRG could be created in 2003 as Xcel Energy, NRG and NRG’s creditors continue to negotiate terms of a possible
prenegotiated plan of reorganization to resolve NRG’s financial difficulties.

In addition to the effects of NRG’s losses, Xcel Energy’s operating results and retained earnings in 2003 could also be affected by the
tax effects of any guarantees or financial commitments to NRG, if such income tax benefits were considered likely of realization in the
foreseeable future. The income tax benefits recorded in 2002 related to Xcel Energy’s investment in NRG, as discussed in Note 11 to
the Consolidated Financial Statements, includes only the tax benefits related to cash and stock investments already made in NRG at
Dec. 31, 2002. Additional tax benefits could be recorded in 2003 at the time that such benefits are considered likely of realization, when
the payment of guarantees and other financial assistance to NRG become probable.

As noted previously, a bankruptcy filing by NRG would have several effects on Xcel Energy’s financial condition and results of operations.
If a bankruptcy filing and other necessary governance actions eliminate Xcel Energy’s control over NRG, then management anticipates that
NRG would no longer be included in Xcel Energy’s consolidated financial statements, prospectively from the date such actions were taken.
Such de-consolidation of NRG would encompass a change in Xcel Energy’s accounting for NRG to the equity method, thus all of NRG’s
assets and liabilities would be presented in a single line on Xcel Energy’s balance sheet at that point. This would reduce Xcel Energy’s debt
leverage ratios and increase its equity ratio as a percent of total capitalization to above 30 percent, thereby reinstating its financing authority
under PUHCA. In addition, the revenues and expenses of NRG would be reported on a net basis as equity income or losses. Losses would
be subject to certain limitations. Also, the operating, investing and financing cash flows of NRG would not be included in Xcel Energy’s
except to the extent cash flowed between Xcel Energy and NRG. Finally, there may be tax effects for guarantees or financial commitments
made by Xcel Energy to NRG related to the bankruptcy or other resolution of NRG’s financial difficulties. See Note 4 to the Consolidated
Financial Statements for further discussion of these possible effects of an NRG bankruptcy filing on Xcel Energy.

Xcel Energy believes that the ultimate resolution of NRG’s financial difficulties and going-concern uncertainty will not affect Xcel
Energy’s ability to continue as a going concern. Xcel Energy is not dependent on cash flows from NRG, nor is Xcel Energy contingently
liable to creditors of NRG in an amount material to Xcel Energy’s liquidity. Xcel Energy believes that its cash flows from regulated
utility operations and anticipated financing capabilities will be sufficient to fund its non-NRG-related operating, investing and financing
requirements. Beyond these sources of liquidity, Xcel Energy believes it will have adequate access to additional debt and equity
financing that is not conditioned upon the outcome of NRG’s financial restructuring plan.

xcel energy inc. and subsidiaries          page 41

To Xcel Energy Inc.:

independent auditors’ report

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, 2002 and 2001, and the related consolidated statements
of operations, common stockholders’ equity and other comprehensive income and cash flows for the three years ended December 31, 2002.
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 years ended December 31, 2002 and 2001, or the consolidated statements of
operations, stockholder’s (deficit)/equity and cash flows for the three years ended December 31, 2002 included in the consolidated
financial statements of the Company, which statements reflect total assets and revenues of 40% and 24% for 2002, respectively, and
total assets and revenues of 45% and 21% for 2001, respectively, and revenues of 20% for 2000, of the related consolidated totals.
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 paragraphs 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 the adoption of SFAS No. 133, “Accounting for Derivative Instruments
and Hedging Activities” on January 1, 2001), 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, 2002 and 2001 and the results of
their operations and their cash flows for each of the three years ended December 31, 2002, in conformity with accounting principles
generally accepted in the United States of America.

As discussed in Note 17 to the consolidated financial statements, effective January 1, 2001, Xcel Energy Inc. and subsidiaries adopted
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.”

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.”

Note 4 to the consolidated financial statements discusses the implications to the Company related to credit and liquidity constraints,
various defaults under credit arrangements and a likely Chapter 11 bankruptcy protection filing at NRG Energy, Inc.

deloitte & touche llp
Minneapolis, Minnesota
March 28, 2003

page 42

xcel energy inc. and subsidiaries

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

report of independent accountants

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, cash flows and
stockholder’s (deficit)/equity present fairly, in all material respects, the financial position of NRG Energy, Inc. and its subsidiaries at
December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three 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 accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern.
As discussed in Note 1 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, it is likely the Company and certain of its
subsidiaries will file 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 Note 26 to the consolidated
financial statements, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments
and Hedging Activities,” on January 1, 2001. 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.

pricewaterhousecoopers llp
Minneapolis, Minnesota
March 28, 2003

xcel energy inc. and subsidiaries          page 43

consolidated statements of operations

(Thousands of dollars, except per share data)

operating revenues

Electric utility
Natural gas utility
Electric and natural gas trading margin
Nonregulated and other
Equity earnings from investments in affiliates

Total operating revenues

operating expenses

Electric fuel and purchased power – utility
Cost of natural gas sold and transported – utility
Cost of sales – nonregulated and other
Other operating and maintenance expenses – utility
Other operating and maintenance expenses – nonregulated
Depreciation and amortization
Taxes (other than income taxes)
Write-downs and disposal losses from investments (see Notes 2 and 3)
Special charges (see Note 2)
Total operating expenses

Operating income (loss)

Interest income
Other nonoperating income
Other nonoperating expense 

interest charges and financing costs

Interest charges – net of amounts capitalized (includes other financing 

costs of $59,724, $21,058 and $20,772, respectively)

Distributions on redeemable preferred securities of subsidiary trusts

Total interest charges and financing costs

Income (loss) from continuing operations before income taxes and minority interest
Income taxes
Minority interest
Income (loss) from continuing operations
Income (loss) from discontinued operations – net of tax (see Note 3)
Income (loss) before extraordinary items
Extraordinary items – net of income taxes of $0, $4,807 and ($8,549), respectively
Net income (loss)
Dividend requirements on preferred stock
Earnings available for common shareholders

weighted average common shares outstanding (thousands)

Basic
Diluted

earnings (loss) per share – basic

Income (loss) from continuing operations
Discontinued operations (see Note 3)
Extraordinary items (see Note 15)
Earnings (loss) per share

earnings (loss) per share – diluted

Income (loss) from continuing operations
Discontinued operations (see Note 3)
Extraordinary items (see Note 15)
Earnings (loss) per share

See Notes to Consolidated Financial Statements

page 44

xcel energy inc. and subsidiaries

Year ended Dec. 31
2001

2002

2000

$ 5,435,377
1,397,800
8,485
2,611,149
71,561
9,524,372

$6,394,737
2,052,651
89,249
2,579,715
217,070
11,333,422

$5,674,485
1,468,880
41,357
1,856,030
182,714
9,223,466

2,199,099
851,987
1,361,466
1,501,602
787,968
1,037,429
318,641
207,290
2,691,223
10,956,705
(1,432,333)

3,171,660
1,517,557
1,318,586
1,506,039
676,408
906,303
316,492
–
62,230
9,475,275
1,858,147

2,580,723
948,145
876,698
1,446,122
533,379
766,746
351,412
–
241,042
7,744,267
1,479,199

45,863
28,167
(30,043)

43,548
17,961
(15,623)

27,480
5,094
(15,994)

879,736
38,344
918,080
(2,306,426)
(627,985)
(17,071)
(1,661,370)
(556,621)
(2,217,991)
–
(2,217,991)
4,241
$(2,222,232)

727,976
38,800
766,776
1,137,257
331,371
68,199
737,687
46,992
784,679
10,287
794,966
4,241
$ 790,725

614,173
38,800
652,973
842,806
299,030
29,994
513,782
32,006
545,788
(18,960)
526,828
4,241
$ 522,587

382,051
382,051

342,952
343,742

337,832
338,111

$

$

$

$

(4.36)
(1.46)
–
(5.82)

$        2.14
0.14
0.03
$        2.31

$        1.51
0.09
(0.06)
$        1.54

(4.36)
(1.46)
–
(5.82)

$        2.13
0.14
0.03
$        2.30

$        1.51
0.09
(0.06)
$        1.54

consolidated statements of cash flows

(Thousands of dollars)

operating activities

Year ended Dec. 31
2001

2002

2000

Net income (loss)
Adjustments to reconcile net income to cash provided by operating activities:

$(2,217,991)

$  794,966

$  526,828

Depreciation and amortization
Nuclear fuel amortization
Deferred income taxes
Amortization of investment tax credits
Allowance for equity funds used during construction
Undistributed equity in earnings of unconsolidated affiliates
Gain on sale of property
Write-downs and losses from investments
Gain on sale of discontinued operations
Noncash special charges – asset write-downs
Conservation incentive accrual adjustments
Unrealized gain on derivative financial instruments
Extraordinary items – net of tax (see Note 15)
Change in accounts receivable
Change in inventories
Change in other current assets
Change in accounts payable
Change in other current liabilities
Change in other noncurrent assets
Change in other noncurrent liabilities

Net cash provided by operating activities

investing activities

Nonregulated capital expenditures and asset acquisitions
Utility capital/construction expenditures
Proceeds from sale of discontinued operations
Allowance for equity funds used during construction
Investments in external decommissioning fund
Equity investments, loans, deposits and sales of nonregulated projects
Restricted cash
Collection of loans made to nonregulated projects
Other investments – net

Net cash used in investing activities

financing activities

Short-term borrowings – net
Proceeds from issuance of long-term debt
Repayment of long-term debt, including reacquisition premiums
Proceeds from issuance of common stock
Proceeds from NRG stock offering
Dividends paid 

Net cash provided by financing activities

Effect of exchange rate changes on cash
Net increase in cash and cash equivalents – discontinued operations

Net increase in cash and cash equivalents – continuing operations
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year

Supplemental disclosure of cash flow information:

Cash paid for interest (net of amounts capitalized)
Cash paid for income taxes (net of refunds received) 

See Notes to Consolidated Financial Statements

1,028,494
48,675
(781,531)
(13,272)
(7,810)
(16,478)
(6,785)
207,290
(2,814)
3,160,374
(9,152)
(8,407)
–
126,073
8,620
67,596
80,338
156,471
(203,997)
99,417
1,715,111

945,555
41,928
11,190
(12,867)
(6,829)
(124,277)
–
–
–
–
(49,271)
(9,804)
(10,287)
218,353
(178,530)
340,478
(325,946)
142,617
(329,442)
136,178
1,584,012

828,780
44,591
62,716
(15,295)
3,848
(87,019)
–
–
–
41,991
19,248
–
18,960
(443,347)
21,933
(484,288)
713,069
183,679
(130,764)
102,795
1,407,725

(1,502,601)
(906,341)
160,791
7,810
(57,830)
(118,844)
(220,800)
22,498
(102,457)
(2,717,774)

(4,259,791)
(1,105,989)
–
6,829
(54,996)
154,845
–
6,374
84,769
(5,167,959)

(2,196,168)
(984,935)
–
(3,848)
(48,967)
(93,366)
–
17,039
(36,749)
(3,346,994)

(663,365)
2,521,375
(362,760)
581,212
–
(496,375)
1,580,087

6,448
56,096

639,968
261,305
901,273

708,335
3,777,075
(860,623)
133,091
474,348
(518,894)
3,713,332

42,386
3,565,227
(1,667,335)
116,678
453,705
(494,992)
2,015,669

(4,566)
(21,570)

360
(57,638)

103,249
158,056
$  261,305

19,122
138,934
$  158,056

640,628
24,935

$  708,560
$  327,018

$  610,584
$  216,087

$

$
$

xcel energy inc. and subsidiaries          page 45

consolidated balance sheets

(Thousands of dollars)

assets
Current assets:

Cash and cash equivalents
Restricted cash
Accounts receivable – net of allowance for bad debts: $92,745 and $37,487, respectively
Accrued unbilled revenues
Materials and supplies inventories – at average cost
Fuel inventory – at average cost
Natural gas inventories – replacement cost in excess of LIFO: $20,502 and $11,331, respectively
Recoverable purchased natural gas and electric energy costs
Derivative instruments valuation – at market
Prepayments and other
Current assets held for sale
Total current assets

Property, plant and equipment, at cost:

Electric utility plant
Nonregulated property and other
Natural gas utility plant
Construction work in progress: utility amounts of $856,008 and $669,895, respectively

Total property, plant and equipment

Less accumulated depreciation
Nuclear fuel – net of accumulated amortization: $1,058,531 and $1,009,855, respectively

Net property, plant and equipment

Other assets:

Investments in unconsolidated affiliates
Notes receivable, including amounts from affiliates of $206,308 and $202,411, respectively
Nuclear decommissioning fund and other investments 
Regulatory assets
Derivative instruments valuation – at market
Prepaid pension asset
Goodwill, net
Intangible assets, net
Other
Noncurrent assets held for sale

Total other assets
Total assets

liabilities and equity
Current liabilities:

Current portion of long-term debt
Short-term debt
Accounts payable
Taxes accrued
Dividends payable
Derivative instruments valuation – at market
Other
Current liabilities held for sale
Total current liabilities

Deferred credits and other liabilities:

Deferred income taxes 
Deferred investment tax credits 
Regulatory liabilities
Derivative instruments valuation – at market
Benefit obligations and other
Minimum pension liability
Noncurrent liabilities held for sale

Total deferred credits and other liabilities

Minority interest in subsidiaries
Commitments and contingencies (see Note 18)

Capitalization (see Statements of Capitalization):

Long-term debt
Mandatorily redeemable preferred securities of subsidiary trusts (see Note 9)
Preferred stockholders’ equity
Common stockholders’ equity
Total liabilities and equity

See Notes to Consolidated Financial Statements

page 46

xcel energy inc. and subsidiaries

Dec. 31

2002

2001

$

901,273 $
305,581
961,060
390,984
321,863
207,200
147,306
63,975
62,206
267,185
108,535
3,737,168

261,305
142,676
1,048,073
495,994
308,593
250,043
126,563
52,583
20,794
307,169
316,621
3,330,414

16,516,790
8,411,088
2,603,545
1,513,807
29,045,230
(10,303,575)
74,139
18,815,794

16,099,655
6,924,894
2,493,028
3,663,371
29,180,948
(9,495,835)
96,315
19,781,428

1,001,380
987,714
732,166
576,403
93,225
466,229
35,538
68,210
364,243
379,772
4,704,880

1,196,702
779,186
695,070
502,442
96,095
378,825
36,916
66,700
360,158
1,530,178
5,642,272
$27,257,842 $28,754,114

$ 7,756,261 $
1,541,963
1,399,195
267,214
75,814
38,767
749,521
520,101
12,348,836

392,938
2,224,812
1,263,690
246,098
130,845
83,122
698,142
429,433
5,469,080

1,283,667
169,696
518,427
102,779
722,264
106,897
155,962
3,059,692

2,134,977
184,148
483,942
42,444
692,090
–
783,297
4,320,898

34,762

614,750

6,550,248
494,000
105,320
4,664,984

11,555,589
494,000
105,320
6,194,477
$27,257,842 $28,754,114

consolidated statements of common stockholders’ equity and other comprehensive income

(Thousands)

Shares

Par Value

Capital in
Excess of
Par Value

Retained
Earnings
(Deficit)

Common Stock Issued

Balance at Dec. 31, 1999
Net income
Currency translation adjustments
Comprehensive income for 2000
Dividends declared:

Cumulative preferred stock of 

Xcel Energy
Common stock

Issuances of common stock – net proceeds
Tax benefit from stock options exercised
Other
Gain recognized from NRG stock offering
Loan to ESOP to purchase shares
Repayment of ESOP loan(a)
Balance at Dec. 31, 2000

Net income
Currency translation adjustments
Cumulative effect of accounting change – 
net unrealized transition loss upon 
adoption of SFAS No. 133 (see 
Note 17)

After-tax net unrealized gains related to 
derivatives accounted for as hedges 
(see Note 17)

After-tax net realized losses on derivative 
transactions reclassified into earnings 
(see Note 17)

Unrealized loss – marketable securities
Comprehensive income for 2001
Dividends declared:

Cumulative preferred stock of 

Xcel Energy
Common stock

Issuances of common stock – net proceeds
Other
Gain recognized from NRG stock offering
Repayment of ESOP loan(a)
Balance at Dec. 31, 2001

Net loss
Currency translation adjustments
Minimum pension liability
After-tax net unrealized losses related to 
derivatives accounted for as hedges 
(see Note 17)

After-tax net realized losses on derivative 
transactions reclassified into earnings 
(see Note 17)

Unrealized loss – marketable securities
Comprehensive income (loss) for 2002
Dividends declared:

Cumulative preferred stock of 

Xcel Energy
Common stock

Issuances of common stock – net proceeds
Acquisition of NRG minority 

common shares

Repayment of ESOP loan(a)
Balance at Dec. 31, 2002

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

335,277

$838,193 

$ 2,288,254 

$ 2,253,800
526,828

5,557

13,892

(4,241)
(492,183)

16

102,785
53

215,933

340,834 

$852,085

$ 2,607,025

$ 2,284,220 

794,966 

Accumulated
Other
Shares Held Comprehensive
Income (Loss)

by ESOP

$(11,606)

$ (78,421)

(78,508)

(20,000)
6,989 
$(24,617)

$(156,929)

(56,693)

Total
Stockholders’
Equity

$ 5,290,220 
526,828 
(78,508)
448,320

(4,241)
(492,183)
116,677 
53 
16 
215,933 
(20,000)
6,989 
$ 5,561,784 

794,966 
(56,693)

(28,780)

(28,780)

43,574

43,574 

19,449
(75)

19,449 
(75)
772,441 

4,967

12,418

120,673

241,891

(4,241)
(516,515)

(27)

345,801 

$864,503

$ 2,969,589

$ 2,558,403

6,053
$(18,564)

$(179,454)

(2,217,991)

30,008
(107,782)

(4,241)
(516,515)
133,091 
(27)
241,891 
6,053 
$ 6,194,477 

(2,217,991)
30,008
(107,782)

(68,266)

(68,266)

28,791
(457)

28,791
(457)
(2,335,697)

(4,241)
(437,113)
581,212 

18,564 
– 

$

28,150

$(269,010)

647,782 
18,564 
$4,664,984 

(4,241)
(437,113)

27,148 

67,870

513,342

25,765

64,412

555,220 

398,714 

$996,785 

$4,038,151 

$  (100,942) 

xcel energy inc. and subsidiaries          page 47

consolidated statements of capitalization

(Thousands of dollars)

long-term debt

NSP-Minnesota Debt
First Mortgage Bonds, Series due:

Dec. 1, 2003–2006, 3.75%–4.1%
March 1, 2003, 5.875%
April 1, 2003, 6.375%
Dec. 1, 2005, 6.125%
Aug. 28, 2012, 8%
March 1, 2011, variable rate, 6.265% at Dec. 31, 2002, and 1.8% at Dec. 31, 2001
March 1, 2019, 8.50% at Dec. 31, 2002, and a variable rate of 2.04% at Dec. 31, 2001
Sept. 1, 2019, 8.5% at Dec. 31, 2002, and a variable rate of 1.76% and 2.04%  at Dec. 31, 2001
July 1, 2025, 7.125%
March 1, 2028, 6.5%
April 1, 2030, 8.50% at Dec. 31, 2002, and 1.85% at Dec. 31, 2001
Dec. 1, 2003–2008, 4.25%–5%

Guaranty Agreements, Series due Feb. 1, 2003–May 1, 2003, 5.375%–7.4%
Senior Notes, due Aug. 1, 2009, 6.875%
Retail Notes, due July 1, 2042, 8%
Employee Stock Ownership Plan Bank Loans, variable rate
Other
Unamortized discount-net

Total

Less redeemable bonds classified as current (see Note 6)
Less current maturities

Total NSP-Minnesota long-term debt

PSCo Debt
First Mortgage Bonds, Series due:

April 15, 2003, 6%
March 1, 2004, 8.125%
Nov. 1, 2005, 6.375%
June 1, 2006, 7.125%
April 1, 2008, 5.625%
June 1, 2012, 5.5%
Oct. 1, 2012, 7.875%
April 1, 2014, 5.875%
Jan. 1, 2019, 5.1%
March 1, 2022, 8.75%
Jan. 1, 2024, 7.25%

Unsecured Senior A Notes, due July 15, 2009, 6.875%
Secured Medium-Term Notes, due Nov. 25, 2003–March 5, 2007, 6.45%–7.11%
Unamortized discount
Capital lease obligations, 11.2% due in installments through May 31, 2025

Total

Less current maturities

Total PSCo long-term debt

SPS Debt
Unsecured Senior A Notes, due March 1, 2009, 6.2%
Unsecured Senior B Notes, due Nov. 1, 2006, 5.125%
Pollution control obligations, securing pollution control revenue bonds due:

July 1, 2011, 5.2%
July 1, 2016, 1.6% at Dec. 31, 2002, and 1.7% at Dec. 31, 2001
Sept. 1, 2016, 5.75% series

Unamortized discount 

Total SPS long-term debt

See Notes to Consolidated Financial Statements

page 48

xcel energy inc. and subsidiaries

Dec. 31

2002

2001

$

9,145(a) $

100,000
80,000
70,000
450,000
13,700 (b)
27,900 (b)
100,000 (b)
250,000
150,000
69,000 (b)
14,090 (a)
28,450 (b)
250,000
185,000
–
427
(8,931)
1,788,781
13,700
212,762
$1,562,319

11,225 (a)
100,000
80,000
70,000
–

13,700 (b)
27,900 (b)
100,000 (b)
250,000
150,000
69,000 (b)
16,090 (a)
29,200 (b)

250,000
–
18,564
390
(5,015)
1,181,054
141,600
11,134
$1,028,320

$ 250,000
100,000
134,500
125,000
18,000 (b)
50,000 (b)
600,000
61,500 (b)
48,750 (b)
146,340
110,000
200,000
175,000
(4,612)
49,747
2,064,225
282,097
$1,782,128

$ 250,000
100,000
134,500
125,000

18,000 (b)
50,000 (b)

–

61,500 (b)
48,750 (b)
147,840
110,000
200,000
190,000
(5,282)
51,921
1,482,229
17,174
$1,465,055

$ 100,000
500,000

$ 100,000
500,000

44,500
25,000
57,300
(1,138)
$ 725,662

44,500
25,000
57,300
(1,425)
$ 725,375

consolidated statements of capitalization

(Thousands of dollars)

long-term debt – continued

NSP-Wisconsin Debt
First Mortgage Bonds, Series due:

Oct. 1, 2003, 5.75%
March 1, 2023, 7.25%
Dec. 1, 2026, 7.375%

City of La Crosse Resource Recovery Bond, Series due Nov. 1, 2021, 6%
Fort McCoy System Acquisition, due Oct. 31, 2030, 7%
Senior Notes, due Oct. 1, 2008, 7.64%
Unamortized discount

Total

Less current maturities

Total NSP-Wisconsin long-term debt

NRG Debt
Remarketable or Redeemable Securities, due March 15, 2005, 7.97%
NRG Energy, Inc. Senior Notes, Series due

Feb. 1, 2006, 7.625%
June 15, 2007, 7.5%
June 1, 2009, 7.5%
Nov. 1, 2013, 8%
Sept. 15, 2010, 8.25%
July 15, 2006, 6.75%
April 1, 2011, 7.75%
April 1, 2031, 8.625%
May 16, 2006, 6.5%

NRG Finance Co. I LLC, due May 9, 2006, various rates
NRG debt secured solely by project assets:

NRG Northeast Generating Senior Bonds, Series due:

Dec. 15, 2004, 8.065%
June 15, 2015, 8.842%
Dec. 15, 2024, 9.292%

South Central Generating Senior Bonds, Series due:

May 15, 2016, 8.962%
Sept. 15, 2024, 9.479%

MidAtlantic – various, due Oct. 1, 2005, 4.625%
Flinders Power Finance Pty, due September 2012, various rates of 6.14%–6.49% 

at Dec. 31, 2002, and 8.56% at Dec. 31, 2001

Brazos Valley, due June 30, 2008, 6.75%
Camas Power Boiler, due June 30, 2007, and Aug. 1, 2007, 3.65% and 3.38%
Sterling Luxembourg #3 Loan, due June 30, 2019, variable rate of 7.86% at Dec. 31, 2001
Crockett Corp. LLP debt, due Dec. 31, 2014, 8.13%
Csepel Aramtermelo, due Oct. 2, 2017, 3.79% and 4.846%
Hsin Yu Energy Development, due November 2006–April 2012, 4%–6.475%
LSP Batesville, due Jan. 15, 2014, 7.164% and July 15, 2025, 8.16%
LSP Kendall Energy, due Sept. 1, 2005, 2.65%
McClain, due Dec. 31, 2005, 6.75%
NEO, due 2005–2008, 9.35%
NRG Energy Center, Inc. Senior Secured Notes, Series due June 15, 2013, 7.31%
NRG Peaking Finance LLC, due 2019, 6.67%
NRG Pike Energy LLC, due 2010, 4.92%
PERC, due 2017–2018, 5.2%
Audrain Capital Lease Obligation, due Dec. 31, 2023, 10%
Saale Energie GmbH Schkopau Capital Lease, due May 2021, various rates
Various debt, due 2003–2007, 0.0%–20.8%

Other

Total

Less current maturities – continuing operations
Less discontinued operations

Total NRG long-term debt

See Notes to Consolidated Financial Statements

Dec. 31

2002

2001

$

40,000
110,000
65,000
18,600 (a)
930
80,000
(1,388)
313,142
40,034
$ 273,108

$

40,000
110,000
65,000
18,600 (a)
963
80,000
(1,475)
313,088
34
$ 313,054

$ 257,552

$ 232,960

125,000
250,000
300,000
240,000
350,000
340,000
350,000
500,000
285,728
1,081,000

126,500
130,000
300,000

450,750
300,000
409,201

99,175
194,362
17,861
360,122
–
–
85,607
314,300
495,754
157,288
7,658
133,099
319,362
155,477
28,695
239,930
333,926
92,573
676
8,831,596
7,193,237
445,729
$1,192,630

125,000
250,000
300,000
240,000
350,000
340,000
350,000
500,000
284,440
697,500

180,000
130,000
300,000

463,500
300,000
420,892

74,886
159,750
20,909
329,842
234,497
169,712
89,964
321,875
499,500
159,885
23,956
62,408
–
–
33,220
239,930
311,867 
147,493
–
8,343,986
210,885
851,196
$7,281,905

xcel energy inc. and subsidiaries          page 49

Dec. 31

2002

2001

$

12,000 $

12,000

17,000

17,000

40,421
41,353
97,895
208,669
14,431
$ 194,238 $

45,181
47,856
35,608
157,645
12,110
145,535

600,000
$ 600,000 $
–
230,000
(3,655)
(9,837)
$ 820,163 $
596,345
$6,550,248 $11,555,589

$ 200,000 $
194,000
100,000
$ 494,000 $

200,000
194,000
100,000
494,000

$

27,500 $
15,000
17,500
20,000
9,980
15,000
104,980
340

$ 105,320 $

27,500
15,000
17,500
20,000
9,980
15,000
104,980
340
105,320

$ 996,785 $
4,038,151
(100,942)
–
(269,010)

864,503
2,969,589
2,558,403
(18,564)
(179,454)
$4,664,984 $ 6,194,477

consolidated statements of capitalization

(Thousands of dollars)

long-term debt – continued

Other Subsidiaries’ Long-Term Debt
First Mortgage Bonds – Cheyenne:

Series due April 1, 2003–Jan. 1, 2024, 7.5%–7.875%
Industrial Development Revenue Bonds, due Sept. 1, 2021–March 1, 2027,

variable rate, 1.7% and 1.8% at Dec. 31, 2002 and 2001

Viking Gas Transmission Co. Senior Notes-Series due:

Oct. 31, 2008–Sept. 30, 2014, 6.65%–8.04%

Various Eloigne Co. Affordable Housing Project Notes, due 2003–2027, 0.3%–9.91%
Other

Total

Less current maturities

Total other subsidiaries’ long-term debt

Xcel Energy Inc. Debt
Unsecured senior notes, due Dec. 1, 2010, 7%
Convertible notes, due Nov. 21, 2007, 7.5%
Unamortized discount

Total Xcel Energy Inc. debt

Total long-term debt

mandatorily redeemable preferred securities of subsidiary trusts

holding as their sole asset the junior subordinated deferrable debentures of:

NSP-Minnesota, due 2037, 7.875%
PSCo, due 2038, 7.6%
SPS, due 2036, 7.85%

Total mandatorily redeemable preferred securities of subsidiary trusts

cumulative preferred stock – authorized 7,000,000 shares of $100 par value;

outstanding shares: 2002, 1,049,800; 2001, 1,049,800

$3.60 series, 275,000 shares
$4.08 series, 150,000 shares
$4.10 series, 175,000 shares
$4.11 series, 200,000 shares
$4.16 series, 99,800 shares
$4.56 series, 150,000 shares
Total

Capital in excess of par value on preferred stock

Total preferred stockholders’ equity

common stockholders’ equity

Common stock – authorized 1,000,000,000 shares of $2.50 par value;

outstanding shares: 2002, 398,714,039; 2001, 345,801,028

Capital in excess of par value on common stock
Retained earnings (deficit)
Leveraged common stock held by ESOP – shares at cost: 2002, 0; 2001, 783,162
Accumulated other comprehensive income (loss)

Total common stockholders’ equity

(a)  Resource recovery financing
(b)  Pollution control financing

See Notes to Consolidated Financial Statements

page 50

xcel energy inc. and subsidiaries

notes to consolidated financial statements

1. summary of significant accounting policies

Merger and Basis of Presentation On Aug. 18, 2000, Northern States Power Co. (NSP) and New Century Energies, Inc. (NCE) merged
and formed Xcel Energy Inc. Each share of NCE common stock was exchanged for 1.55 shares of Xcel Energy common stock. NSP
shares became Xcel Energy shares on a one-for-one basis. Cash was paid in lieu of any fractional shares of Xcel Energy common stock.
The merger was structured as a tax-free, stock-for-stock exchange for shareholders of both companies, except for fractional shares, and
accounted for as a pooling-of-interests. At the time of the merger, Xcel Energy registered as a holding company under the PUHCA.
References herein to Xcel Energy relates to Xcel Energy, Inc. and its consolidated subsidiaries.

Pursuant to the merger agreement, NCE was merged with and into NSP. NSP, as the surviving legal corporation, changed its name to
Xcel Energy. Also, as part of the merger, NSP transferred its existing utility operations that were being conducted directly by NSP at the
parent company level to a newly formed, wholly owned subsidiary of Xcel Energy, which was renamed NSP-Minnesota.

Consistent with pooling accounting requirements, results and disclosures for all periods prior to the merger have been restated for
consistent reporting with post-merger organization and operations. All earnings-per-share amounts previously reported for NSP
and NCE have been restated for presentation on an Xcel Energy share basis.

Business and System of Accounts Xcel Energy’s domestic utility subsidiaries are engaged principally in the generation, purchase, transmission,
distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. Xcel Energy and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The utility subsidiaries are subject to regulation by the FERC and state utility
commissions. All of the utility companies’ accounting records conform to the FERC uniform system of accounts or to systems required
by various state regulatory commissions, which are the same in all material aspects.

Principles of Consolidation Xcel Energy directly owns six utility subsidiaries that serve electric and natural gas customers in 12 states.
These six utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo, SPS, BMG and Cheyenne. Their service territories include
portions of Arizona, Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Wisconsin
and Wyoming. During the period covered by this report, Xcel Energy’s regulated businesses also included Viking, which was sold in
January 2003, and WGI.

Xcel Energy also owns or has an interest in a number of nonregulated businesses, the largest of which is NRG Energy, Inc., an independent
power producer. Xcel Energy owned 100 percent of NRG until the second quarter of 2000, when NRG completed its initial public offering,
and 82 percent until a secondary offering was completed in March 2001. At Dec. 31, 2001, Xcel Energy indirectly owned approximately
74 percent of NRG. During the second quarter of 2002, Xcel Energy acquired the 26 percent of NRG shares that it did not own through
a tender offer and merger. See Note 4 to the Consolidated Financial Statements for further discussion of the acquisition of minority
NRG common shares.

In addition to NRG, Xcel Energy’s nonregulated subsidiaries include Utility Engineering Corp. (engineering, construction and design),
Seren Innovations, Inc. (broadband telecommunications services), e prime inc. (natural gas marketing and trading), Planergy International,
Inc. (enterprise energy management solutions), Eloigne Co. (investments in rental housing projects that qualify for low-income housing tax
credits) and Xcel Energy International Inc. (an international independent power producer).

Xcel Energy owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional
subsidiaries: Xcel Energy Wholesale Energy Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy
Retail Holdings Inc., Xcel Energy Communications Group Inc., Xcel Energy WYCO Inc. and Xcel Energy O & M Services Inc.
Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.

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

Revenue Recognition Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to
customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs
on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the
last meter reading are estimated and the corresponding unbilled revenue is estimated.

Xcel Energy’s utility subsidiaries have various rate adjustment mechanisms in place that currently provide for the recovery of certain
purchased natural gas and electric energy costs. These cost adjustment tariffs may increase or decrease the level of costs recovered
through base rates and are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total
amount collected under the clauses and the recoverable costs incurred. In addition Xcel Energy presents its revenue net of any excise or
other fiduciary-type taxes or fees.

xcel energy inc. and subsidiaries          page 51

notes to consolidated financial statements

PSCo’s electric rates in Colorado are adjusted under the ICA mechanism, which takes into account changes in energy costs and certain
trading revenues and expenses that are shared with the customer. For fuel and purchased energy expense incurred beginning Jan. 1, 2003,
the recovery mechanism shall be determined by the CPUC in the PSCo 2002 general rate case. In the interim, 2003 fuel and purchased
energy expense is recovered through an interim adjustment clause.

NSP-Minnesota’s rates include a cost-of-fuel and cost-of-gas recovery mechanism allowing dollar-for-dollar recovery of the respective
costs, which are trued-up on a two-month and annual basis, respectively.

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

In Colorado, PSCo operates under an electric performance-based regulatory plan, which results in an annual earnings test. NSP-Minnesota’s
and PSCo’s rates include monthly adjustments for the recovery of conservation and energy management program costs, which are
reviewed annually.

SPS’ rates in Texas have fixed fuel factor and periodic fuel filing, reconciling and reporting requirements, which provide cost recovery.
In New Mexico, SPS also has a monthly fuel and purchased power cost recovery factor.

Trading Operations In June 2002, the EITF of the FASB reached a partial consensus on Issue No. 02-03 – “Recognition and Reporting
of Gains and Losses on Energy Trading Contracts” under EITF Issue No. 98-10 - “Accounting for Contracts Involved in Energy Trading
and Risk Management Activities” (EITF No. 02-03). The EITF concluded that all gains and losses related to energy trading activities
within the scope of EITF No. 98-10, whether or not settled physically, must be shown net in the statement of operations, effective for
periods ending after July 15, 2002. Xcel Energy has reclassified revenue from trading activities for all comparable prior periods reported.
Such energy trading activities recorded as a component of Electric and Gas Trading Costs, which have been reclassified to offset Electric
and Gas Trading Revenues to present Electric and Gas Trading Margin on a net basis, were $3.3 billion, $3.1 billion and $2 billion for the
years ended Dec. 31, 2002, 2001 and 2000, respectively. This reclassification had no impact on operating income or reported net income.

On Oct. 25, 2002, the EITF rescinded EITF No. 98-10. With the rescission of EITF No. 98-10, energy trading contracts that do not
also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts. Contracts previously recorded
at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133 must be restated to historical cost through a
cumulative effect adjustment. Xcel Energy does not expect the effect of adopting this decision to be material.

Xcel Energy’s commodity trading operations are conducted by NSP-Minnesota (electric), PSCo (electric) and e prime (natural gas).
Pursuant to a joint operating agreement ( JOA), approved by the FERC as part of the merger, some of the electric trading activity
conducted at NSP-Minnesota and PSCo is apportioned to the other operating utilities of Xcel Energy. Trading revenue and costs do
not include the revenue and production costs associated with energy produced from Xcel Energy’s generation assets or energy and
capacity purchased to serve native load. Trading results are recorded using the mark-to-market accounting. In addition, trading results
include the impacts of the ICA rate-sharing mechanism. Trading revenue and costs associated with NRG’s operations are included in
nonregulated margins. For more information, see Notes 16 and 17 to the Consolidated Financial Statements.

Property, Plant, Equipment and Depreciation Property, plant and equipment is stated at original cost. The cost of plant includes direct
labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired, plus net removal cost, is
charged to accumulated depreciation and amortization. Significant additions or improvements extending asset lives are capitalized, while
repairs and maintenance are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of
property are charged to operating expenses.

Xcel Energy determines the depreciation of its plant by using the straight-line method, which spreads the original cost equally over the
plant’s useful life. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.4 percent, 3.1 percent
and 3.3 percent for the years ended Dec. 31, 2002, 2001 and 2000, respectively.

Property, plant and equipment includes approximately $18 million and $25 million, respectively, for costs associated with the engineering
design of the future Pawnee 2 generating station and certain water rights obtained for another future generating station in Colorado.
PSCo is earning a return on these investments based on its weighted average cost of debt in accordance with a CPUC rate order.

Allowance for Funds Used During Construction (AFDC) and Capitalized Interest  AFDC, a noncash item, represents the cost of capital
used to finance utility construction activity. AFDC is computed by applying a composite pretax rate to qualified construction work
in progress. The amount of AFDC capitalized as a utility construction cost is credited to other nonoperating income, for equity capital,
and interest charges, for debt capital. AFDC amounts capitalized are included in Xcel Energy’s rate base for establishing utility service
rates. In addition to construction-related amounts, AFDC also is recorded to reflect returns on capital used to finance conservation
programs in Minnesota. Interest capitalized for all Xcel Energy entities, as AFDC for utility companies, was approximately $83 million
in 2002, $56 million in 2001 and $23 million in 2000.

page 52

xcel energy inc. and subsidiaries

notes to consolidated financial statements

Decommissioning Xcel Energy accounts for the future cost of decommissioning – or permanently retiring – its nuclear generating plants
through annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning
costs. Our decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends
over the estimated lives of the plants. The calculation assumes that NSP-Minnesota and NSP-Wisconsin will recover those costs through
rates. For more information on nuclear decommissioning, see Note 19 to the Consolidated Financial Statements.

PSCo also previously operated a nuclear generating plant, which has been decommissioned and repowered using natural gas. PSCo’s
costs associated with decommissioning were deferred and are being amortized consistent with regulatory recovery.

Nuclear Fuel Expense Nuclear fuel expense, which is recorded as our nuclear generating plants use fuel, includes the cost of fuel used in
the current period, as well as future disposal costs of spent nuclear fuel. In addition, nuclear fuel expense includes fees assessed by the
U.S. Department of Energy (DOE) for NSP-Minnesota’s portion of the cost of decommissioning the DOE’s fuel enrichment facility.

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

We record estimated remediation costs, excluding inflationary increases and possible reductions for insurance coverage and rate recovery.
The estimates are based on our experience, our assessment of the current situation and the technology currently available for use in the
remediation. We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated
responsible parties, we estimate and record only our share of the cost. We treat any future costs of restoring sites where operation may
extend indefinitely as a capitalized cost of plant retirement. The depreciation expense levels we can recover in rates include a provision
for these estimated removal costs.

Income Taxes Xcel Energy and its domestic subsidiaries, other than NRG and its domestic subsidiaries, file consolidated federal income
tax returns. NRG and its domestic subsidiaries were included in Xcel Energy’s consolidated federal income tax returns prior to NRG’s
March 2001 public equity offering, but filed consolidated federal income tax returns, with NRG as the common parent, separate and apart
from Xcel Energy for the periods of March 13, 2001, through Dec. 31, 2001, and Jan. 1, 2002, through June 3, 2002. Since becoming
wholly owned indirect subsidiaries of Xcel Energy on June 3, 2002, NRG and its domestic subsidiaries have not been reconsolidated
with Xcel Energy for federal income tax purposes, and each of NRG and its domestic subsidiaries will file separate federal income tax
returns as a result of their inclusion in the Xcel Energy consolidated federal income tax return within the last five years. Xcel Energy
and its domestic subsidiaries file combined and separate state income tax returns. NRG and one or more of its domestic subsidiaries will
be included in some, but not all, of these combined returns in 2002. Federal income taxes paid by Xcel Energy, as parent of the Xcel
Energy consolidated group, are allocated to the Xcel Energy subsidiaries based on separate company computations of tax. A similar allocation
is made for state income taxes paid by Xcel Energy in connection with combined state filings. In accordance with PUHCA requirements,
the holding company also allocates its own net income tax benefits to its direct subsidiaries based on the positive tax liability of each
company. Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income, and between the book
and tax bases of assets and liabilities. Xcel Energy uses the tax rates that are scheduled to be in effect when the temporary differences
are expected to turn around, or reverse.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, we account for the reversal of some
temporary differences as current income tax expense. We defer investment tax credits and spread their benefits over the estimated lives
of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which we
summarize in Note 20 to the Consolidated Financial Statements. We discuss our income tax policy for international operations in Note 11
to the Consolidated Financial Statements.

Foreign Currency Translation Xcel Energy’s foreign operations generally use the local currency as their functional currency in translating
international operating results and balances to U.S. currency. Foreign currency denominated assets and liabilities are translated at the
exchange rates in effect at the end of a reporting period. Income, expense and cash flows are translated at weighted-average exchange rates
for the period. We accumulate the resulting currency translation adjustments and report them as a component of Other Comprehensive
Income in common stockholders’ equity. When we convert cash distributions made in one currency to another currency, we include those
gains and losses in the results of operations as a component of Other Nonoperating Income. Currency exchange transactions resulted in
a pretax gain (loss) of $30 million in 2002, $(57) million in 2001 and $(79) million in 2000.

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

xcel energy inc. and subsidiaries          page 53

notes to consolidated financial statements

On Jan. 1, 2001, Xcel Energy adopted SFAS No. 133. For more information on the impact of SFAS No. 133, see Note 17 to the
Consolidated Financial Statements.

For further discussion of Xcel Energy’s risk management and derivative activities, see Notes 16 and 17 to the Consolidated
Financial Statements.

Use of Estimates In recording transactions and balances resulting from business operations, Xcel Energy uses estimates based on the best
information available. We use estimates for such items as plant depreciable lives, tax provisions, uncollectible amounts, environmental
costs, unbilled revenues and actuarially determined benefit costs. We revise the recorded estimates when we get better information or
when we can determine actual amounts. Those revisions can affect operating results. Each year we also review the depreciable lives of
certain plant assets and revise them if appropriate.

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

Restricted cash consists primarily of cash collateral for letters of credit issued in relation to project development activities. In addition,
it includes funds held in trust accounts to satisfy the requirements of certain debt agreements and funds held within NRG’s projects
that are restricted in their use. Restricted cash is classified as a current asset as all restricted cash is designated for interest and principal
payments due within one year.

Cash and cash equivalents includes $385 million held by NRG, which is not legally restricted. However, this cash is not available for
Xcel Energy’s general corporate purposes.

Inventory All inventory is recorded at average cost, with the exception of natural gas in underground storage at PSCo, which is recorded
using last-in-first-out pricing.

Regulatory Accounting Our regulated utility subsidiaries account for certain income and expense items using SFAS No. 71 – “Accounting
for the Effects of Certain Types of Regulation.” Under SFAS No. 71:

– we defer certain costs, which would otherwise be charged to expense, as regulatory assets based on our expected ability to recover

them in future rates; and

– we defer certain credits, which would otherwise be reflected as income, as regulatory liabilities based on our expectation they will

be returned to customers in future rates.

We base our estimates of recovering deferred costs and returning deferred credits on specific ratemaking decisions or precedent for each
item. We amortize regulatory assets and liabilities consistent with the period of expected regulatory treatment. See more discussion of
regulatory assets and liabilities at Note 20 to the Consolidated Financial Statements.

Stock-Based Employee Compensation We have several stock-based compensation plans. We account for those plans using the intrinsic
value method. We do not record compensation expense for stock options because there is no difference between the market price and
the purchase price at grant date. We do, however, record compensation expense for restricted stock awarded to certain employees, which
is held until the restriction lapses or the stock is forfeited. For more information on stock compensation impacts, see Note 12 to the
Consolidated Financial Statements.

Intangible Assets During 2002, Xcel Energy adopted SFAS No. 142 – “Goodwill and Other Intangible Assets,” which requires new
accounting for intangible assets and goodwill. Intangible assets with finite lives will be amortized over their economic useful lives and
periodically reviewed for impairment. Goodwill is no longer being amortized, but will be tested for impairment annually and on an
interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below
its carrying value.

Xcel Energy had goodwill of approximately $35 million at Dec. 31, 2002, which will not be amortized, consisting of $27.8 million of
project-related goodwill at NRG and $7.7 million of project-related goodwill at Utility Engineering. As part of Xcel Energy’s acquisition
of NRG’s minority shares (see Note 4), $62 million of excess purchase price was allocated to fixed assets related to projects where the fair
value of the fixed assets was higher than the carrying value as of June 2002, to prepaid pension assets, and to other assets. Net goodwill
decreased between 2002 and 2001 due to asset sales at NRG. During 2002, Xcel Energy performed impairment tests of its intangible
assets. Tests have concluded that no write-down of these intangible assets is necessary.

Intangible assets with finite lives continue to be amortized, and the aggregate amortization expense recognized in the years ended
Dec. 31, 2002, 2001 and 2000, were $4.3 million, $6.3 million and $3.9 million, respectively. The annual aggregate amortization
expense for each of the five succeeding years is expected to approximate $3.4 million. Intangible assets consisted of the following:

page 54

xcel energy inc. and subsidiaries

notes to consolidated financial statements

(Millions of dollars)

Not amortized:
Goodwill

Amortized:

Service contracts
Trademarks
Prior service costs
Other (primarily franchises)

Dec. 31, 2002

Dec. 31, 2001

Gross Carrying
Amount

Accumulated
Amortization

Gross Carrying
Amount

Accumulated 
Amortization 

$42.5

$73.2
$ 5.0
$ 6.9
$ 2.0

$ 7.0

$17.9
$ 0.5
$
–
$ 0.5

$44.1

$76.2
$ 5.0
$
–
$ 1.9

$ 7.2

$15.6
$ 0.4
$
–
$ 0.4

The following table summarizes the pro forma impact of implementing SFAS No. 142 at Jan. 1, 2000, on the net income for the periods
presented. The pro forma income adjustment to remove goodwill amortization is not material to earnings per share previously reported.

(Millions of dollars)

Reported income from continuing operations
Add back: goodwill amortization (after tax)
Adjusted income from continuing operations
Reported income before extraordinary items
Add back: goodwill amortization (after tax)
Adjusted income before extraordinary items
Reported net income 
Add back: goodwill amortization (after tax)
Adjusted net income 
Earnings per share

Year Ended

Dec. 31, 2001

Dec. 31, 2000

$737.7
1.2
$738.9
$784.7
3.2
$787.9
$795.0
3.2
$798.2
$ 2.31

$513.8
1.8
$515.6
$545.8
2.5
$548.3
$526.8
2.5
$529.3
$ 1.55

Asset Valuation On Jan. 1, 2002, Xcel Energy adopted SFAS No. 144 – “Accounting for the Impairment or Disposal of Long-Lived
Assets,” which supercedes previous guidance for measurement of asset impairments. Xcel Energy did not recognize any asset impairments
as a result of the adoption. The method used in determining fair value was based on a number of valuation techniques, including present
value of future cash flows. SFAS No. 144 is being applied to NRG’s sale of assets as they are reclassified to “held for sale” and discontinued
operations (see Note 3). In addition, SFAS No. 144 is being applied to test for and measure impairment of NRG’s long-lived assets held for
use (primarily energy projects in operation and under construction), as discussed further in Note 2 to the Consolidated Financial Statements.

Deferred Financing Costs Other assets also included deferred financing costs, net of amortization, of approximately $198 million at
Dec. 31, 2002. We are amortizing these financing costs over the remaining maturity periods of the related debt.

Diluted Earnings Per Share Diluted earnings per share is based on the weighted average number of common and common equivalent
shares outstanding each period. However, no common equivalent shares are included in the computation when a loss from continuing
operations exists due to their antidilutive effect (that is, they would make the loss per share smaller). Therefore, common equivalent
shares of approximately 5.4 million were excluded from the diluted earnings-per-share computations for the year ended Dec. 31, 2002,
as shown in Note 12.

FASB Interpretation No. 46 (FIN No. 46) In January 2003, the 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, that requirement has been
applied to subsidiaries in which an enterprise has a majority voting interest, but in many circumstances the enterprise’s consolidated
financial statements do not include the consolidations of variable interest entities with which it has similar relationships but no majority
voting interest. Under FIN No. 46, the voting interest approach is not effective in identifying controlling financial interest. As a result,
Xcel Energy expects that it will have to consolidate its affordable housing investments made through Eloigne, which currently are
accounted for under the equity method.

As of Dec. 31, 2002, the assets of these entities were approximately $155 million and long-term liabilities were approximately $87 million.
Currently, investments of $62 million are reflected as a component of investments in unconsolidated affiliates in the Dec. 31, 2002,
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 apply. If determining carrying amounts as required is impractical, then 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. Had Xcel Energy adopted FIN No. 46 requirements early in 2002,
there would have been no material impact to net income. Xcel Energy plans to adopt FIN No. 46 when required in the third quarter of 2003.

xcel energy inc. and subsidiaries          page 55

notes to consolidated financial statements

Reclassifications We reclassified certain items in the 2000 and 2001 statements of operations and the 2001 balance sheet to conform to the
2002 presentation. These reclassifications had no effect on net income or earnings per share. The reclassifications were primarily to
conform the presentation of all consolidated Xcel Energy subsidiaries to a standard corporate presentation.

Special charges included in Operating Expenses for the years ended Dec. 31, 2002, 2001 and 2000, include the following:

2. special charges and asset impairments

(Millions of dollars)

NRG special charges:

Asset impairments – continuing operations
Financial restructuring and NEO costs

Total NRG special charges

Regulated utility special charges:

Regulatory recovery adjustment (SPS)
Restaffing (utility and service companies)
Post-employment benefits (PSCo) 
Merger costs – severance and related costs
Merger costs – transaction-related
Other merger costs – transition and integration

Total regulated utility special charges

Other nonregulated special charges:

Asset impairments
Holding company NRG restructuring charges

Total nonregulated special charges

Total special charges

2002

2001

2000

$2,545
111
2,656

5
9
–
–
–
–
14

16
5
21
$2,691

$  –
–
–

–
39
23
–
–
–
62

–
–
–
$62

$ –
–
– 

–
–
–
77
52
70
199

42
–
42
$241

NRG Asset Impairments As discussed further in Note 4, NRG in 2002 experienced credit-rating downgrades, defaults under numerous
credit agreements, increased collateral requirements and reduced liquidity. These events resulted in impairment reviews of a number
of NRG assets. NRG completed an analysis of the recoverability of the asset-carrying values of its projects, factoring in the probability
weighting of different courses of action available to NRG, given its financial position and liquidity constraints. This approach was
applied consistently to asset groups with similar uncertainties and cash flow streams. As a result, NRG determined that many of its
construction projects and its operational projects became impaired during 2002 and should be written down to fair market value. In
applying those provisions, NRG management considered cash flow analyses, bids and offers related to those projects. The resulting
impairments were recognized as Special Charges in 2002, as follows:

(Millions of dollars)

Projects in Construction or Development
Nelson
Pike

Bourbonnais
Meriden
Brazos Valley
Kendall, Batesville and 

other expansion projects

Langage (UK)
Turbines and other costs

Total

Operating Projects
Audrain
Somerset
Bayou Cove
Other

Total

Total NRG impairment charges

Status

Pretax Charge

Fair Value Basis

Terminated 
Terminated – Chapter 7 involuntary 
bankruptcy petition filed October 2002
Terminated
Terminated
Foreclosure completed in January 2003

Terminated
Terminated
Equipment being marketed

Operating at a loss
Operating at a loss
Operating at a loss
Operating at a loss

$ 468

Similar asset prices

Similar asset prices
Similar asset prices
Similar asset prices
Projected cash flows

Projected cash flows
Estimated market price
Similar asset prices

Projected cash flows
Projected cash flows
Projected cash flows
Projected cash flows

402
265
144
103

120
42 
702
$2,246 

$

66
49
127
57
$ 299
$2,545

All of these impairment charges relate to assets considered held for use under SFAS No. 144. For fair values determined by similar
asset prices, the fair value represents NRG’s current estimate of recoverability, if the project assets were to be sold. For fair values
determined by estimated market price, the fair value represents a market bid or appraisal received by NRG that NRG believes is
best reflective of fair value. For fair values determined by projected cash flows, the fair value represents a discounted cash flow
amount over the remaining life of each project that reflects project-specific assumptions for long-term power pool prices, escalated
future project operating costs and expected plant operation given assumed market conditions.

page 56

xcel energy inc. and subsidiaries

notes to consolidated financial statements

Additional asset impairments may be recorded by NRG in periods subsequent to Dec. 31, 2002, given the changing business conditions
and the resolution of the pending financial restructuring plan. Management is unable to determine the possible magnitude of any
additional asset impairments, but it could be material.

NRG Financial Restructuring and NEO Costs In 2002, NRG expensed a pretax charge of $26 million for expected severance and related
benefits related to its financial restructuring and business realignment. Through Dec. 31, 2002, severance costs have been recognized for all
employees who had been terminated as of that date. See Note 4 for further discussion of NRG financial restructuring activities and
developments. These costs also include a charge related to NRG’s NEO landfill gas generation operations for the estimated impact
of a dispute settlement with NRG’s partner on the NEO project, Fortistar.

2002 Regulatory Recovery Adjustment – SPS In late 2001, SPS filed an application requesting recovery of costs incurred to comply
with transition to retail competition legislation in Texas and New Mexico. During 2002, SPS entered into a settlement agreement
with intervenors regarding the recovery of restructuring costs in Texas, which was approved by the state regulatory commission in
May 2002. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million.

2002 Other Nonregulated Asset Impairments In 2002, a subsidiary of Xcel Energy 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 International’s investment. Nonregulated
asset impairments include a write-down of approximately $13 million for this Argentina facility.

2002 Holding Company NRG Restructuring Charges In 2002, the Xcel Energy holding company incurred approximately $5 million for
charges related to NRG’s financial restructuring.

2002 and 2001 – Utility Restaffing During 2001, Xcel Energy expensed pretax special charges of $39 million for expected staff consolidation
costs for an estimated 500 employees in several utility operating and corporate support areas of Xcel Energy. In 2002, the identification of
affected employees was completed and additional pretax special charges of $9 million were expensed for the final costs of staff consolidations.
Approximately $6 million of these restaffing costs were allocated to Xcel Energy’s Utility Subsidiaries. All 564 of accrued staff terminations
have occurred. See the summary of costs below.

2001 – Post-employment Benefits PSCo adopted accrual accounting for post-employment benefits under SFAS No. 112 – “Employers
Accounting for Post-employment Benefits” in 1994. The costs of these benefits had been recorded on a pay-as-you-go basis and,
accordingly, PSCo recorded a regulatory asset in anticipation of obtaining future rate recovery of these transition costs. PSCo
recovered its FERC jurisdictional portion of these costs. PSCo requested approval to recover its Colorado retail natural gas jurisdictional
portion in a 1996 retail rate case and its retail electric jurisdictional portion in the electric earnings test filing for 1997. In the 1996 rate
case, the CPUC allowed recovery of post-employment benefit costs on an accrual basis, but denied PSCo’s request to amortize the transition
costs’ regulatory asset. Following various appeals, which proved unsuccessful, PSCo wrote off $23 million pretax of regulatory assets
related to deferred post-employment benefit costs as of June 30, 2001.

2000 – Merger Costs At the time of the NCE and NSP-Minnesota merger in 2000, Xcel Energy expensed pretax special charges totaling
$241 million.

The pretax charges included $199 million associated with the costs of merging regulated operations. Of these pretax charges, $52 million
related to one-time, transaction-related costs incurred in connection with the merger of NSP and NCE, and $147 million pertained to
incremental costs of transition and integration activities associated with merging NSP and NCE to begin operations as Xcel Energy.
The transition costs include approximately $77 million for severance and related expenses associated with staff reductions. All 721 of
accrued staff terminations have occurred. The staff reductions were nonbargaining positions mainly in corporate and operations support
areas. Other transition and integration costs include amounts incurred for facility consolidation, systems integration, regulatory transition,
merger communications and operations integration assistance. An allocation of the regulated portion of merger costs was made to utility
operating companies using a basis consistent with prior regulatory filings, in proportion to expected merger savings by company and
consistent with service company cost allocation methodologies utilized under the PUHCA requirements.

The pretax charges also included $42 million of asset impairments and other costs resulting from the post-merger strategic alignment of
Xcel Energy’s nonregulated businesses.

xcel energy inc. and subsidiaries          page 57

notes to consolidated financial statements

Accrued Special Charges – The following table summarizes activity related to accrued special charges in 2002 and 2001:

(Millions of dollars)

Balance at Dec. 31, 1999
2000 accruals recorded – merger costs
Adjustments/revisions to prior accruals
Cash payments made in 2000
Balance at Dec. 31, 2000

2001 accruals recorded – restaffing
Adjustments/revisions to prior accruals
Cash payments made in 2001
Balance at Dec. 31, 2001

2002 accruals recorded – various
Adjustments/revisions to prior accruals
Cash payments made in 2002
Balance at Dec. 31, 2002

Utility
Severance *

NRG
Severance **

Merger
Transition

Costs *

$ –
77
–
(29)
48

39
-
(50)
37

–
9
(33)
$13

$ –
–
–
–
–

–
–
–
–

23
–
(5)
$18

$ –
70
–
(63)
7

–
–
(7)
–

–
–
–
$ –

* Reported on the balance sheet in Other Current Liabilities.
** $15.5 million reported on the balance sheet in Other Current Liabilities and $2.5 million reported in Benefit Obligations and Other.

3. discontinued operations and losses on equity investments 

Pursuant to the requirements of SFAS No. 144, NRG has classified and is accounting for certain of its assets as held for sale at
Dec. 31, 2002. SFAS No. 144 requires that assets held for sale be valued on an asset-by-asset basis at the lower of carrying amount
or fair value less costs to sell. In applying those provisions, NRG’s management considered cash flow analyses, bids and offers related
to those assets and businesses. As a result, NRG recorded estimated after-tax losses on assets held for sale of $5.8 million for the
year ended Dec. 31, 2002. This amount is included in Income (loss) from discontinued operations in the accompanying Statement
of Operations. In accordance with the provisions of SFAS No. 144, assets held for sale will not be depreciated commencing with
their classification as such.

discontinued operations
During 2002, NRG agreed to sell certain assets and has entered into purchase and sale agreements or has committed to a plan to sell.
As of Dec. 31, 2002, five international projects (Bulo Bulo, Csepel, Entrade, Killingholme and Hsin Yu) and one domestic project
(Crockett Cogeneration) had been classified as held for sale. The assets and liabilities of these six projects have been reclassified to the
held-for-sale category on the balance sheet and meet the requirements of SFAS No. 144 for discontinued operations reporting. As of
Dec. 31, 2002, only Hsin Yu and Killingholme’s assets and liabilities remain in the held-for-sale categories of the balance sheet as the
other entities have been sold. Accordingly, operating results and estimated losses on disposal of these six projects have been reclassified
to discontinued operations for current and prior periods.

Projects included in discontinued operations are as follows:

(Millions of dollars)
Project

Crockett Cogeneration
Bulo Bulo
Csepel
Entrade
Killingholme*
Hsin Yu
Other

Total

Location

United States
Bolivia
Hungary
Czech Republic
United Kingdom
Taiwan
Various

Pretax Disposal
Gain (Loss)

$(11.5)
(10.6)
21.2
2.8
–
–
0.9
$ 2.8

Status

Sale final 2002
Sale final 2002 
Sale final 2002 
Sale final 2002
Sale final 2003
Held for sale
Sales final 2002

* The foreclosure of Killingholme in January 2003 for a gain of $182.3 million

page 58

xcel energy inc. and subsidiaries

notes to consolidated financial statements

(Thousands of dollars)

Operating revenue
Operating and other expenses
Pretax (loss)/income from operations of discontinued components
Income tax (benefit)/expense
(Loss)/income from operations of discontinued components

Estimated pretax gain on disposal of discontinued components
Income tax (benefit)/expense
Gain on disposal of discontinued components

Net (loss)/income on discontinued operations

Year Ended
Dec. 31
2002

Year Ended
Dec. 31
2001

Year Ended
Dec. 31
2000

$  729,408
1,300,131
(570,723)
(8,296)
(562,427)

2,814
(2,992)
5,806

$597,181
544,837
52,344
5,352
46,992

$347,848
310,007
37,841
5,835
32,006

–
–
–

–
–
–

$(556,621)

$ 46,992

$ 32,006

Special charges from discontinued operations included in Operating and Other Expenses previously include the following:

(Thousands of dollars)

Asset impairments
Killingholme
Hsin Yu

Severance and other charges
Total special charges

2002

2001

2000

$  477,868
121,864
599,732
7,389
$  607,121

$   –
–
–
–
$   –

$   –
–
–
–
$   –

These impairment charges relate to assets considered held for sale under SFAS No. 144, as of Dec. 31, 2002. In January 2003, Killingholme
was transferred to the project lenders. Hsin Yu has historically operated at a loss and its funding has been discontinued as of Dec. 31, 2002.
The fair values represent discounted cash flows over the remaining life of each project and reflect project-specific assumptions for long-term
power pool prices, escalated future project operating costs and expected plant operation given assumed market conditions.

The major classes of assets and liabilities held for sale are as follows as of Dec. 31:

(Thousands of dollars)

Cash
Receivables, net
Derivative instruments valuation – at market
Other current assets
Current assets held for sale

Property, plant and equipment, net
Derivative instruments valuation – at market
Other noncurrent assets
Noncurrent assets held for sale

Current portion of long-term debt
Accounts payable – trade
Other current liabilities
Current liabilities held for sale

Long-term debt
Deferred income tax
Derivative instruments valuation – at market
Other noncurrent liabilities
Noncurrent liabilities held for sale

2002

2001

$ 23,911
28,220
29,795
26,609
108,535

274,544
87,803
17,425
379,772

445,656
55,707
18,738
520,101

73
129,640
12,302
13,947
$155,962

$  99,171
129,220
38,996
49,234
316,621

1,383,690
83,588
62,900
1,530,178

289,269
97,654
42,510
429,433

561,927
154,573
15,131
51,666
$783,297

Included in other noncurrent assets held for sale is approximately $27 million, net of $3.6 million of amortization, of goodwill and
$11 million, net of $1.9 million of amortization, of intangible assets as of Dec. 31, 2002. There are no amounts of goodwill or intangible
assets included in noncurrent assets held for sale.

losses related to nrg equity investments 
As of Dec. 31, 2002, several projects of NRG incurred losses related to disposal transactions or asset impairments. In the accompanying
financial statements, the operating results of these projects are classified in equity earnings from investments in affiliates, and write-downs
of the carrying amount of the investments and losses on disposal have been classified and reported as a component of write-downs and
disposal losses from investments. During 2002, NRG recorded write-downs and losses on disposal of $196.2 million of equity investments
as follows:

xcel energy inc. and subsidiaries          page 59

notes to consolidated financial statements

(Millions of dollars)
Project

Collinsville
EDL
ECKG
SRW Cogeneration
Mt. Poso
Kingston
Kondapalli
Loy Yang
NEO MESI
Other

Total

Location

Australia
Australia
Czech Republic
United States
United States
Canada
India
Australia
United States

Impairment
Loss

Disposal
Gain (Loss)

–
$
–
$
–
$
–
$
–
$
$
–
$ (12.7)
$(111.4)
$
–
$ (14.7)
$(138.8)

$ (3.6)
$(14.2)
$ (2.1)
$(48.4)
$ (1.0)
9.9
$
–
$
–
$
2.0
$
$
–
$(57.4)

Status

Sale final 2002
Sale final 2002
Sale final 2003
Sale final 2002
Sale final 2002
Sale final 2002
Sale pending
Operating
Sale final 2002

During fourth quarter 2002, NRG and the other owners of the Loy Yang project engaged in a joint marketing of the project for possible sale.
Based on a new market valuation and negotiations with a potential purchaser, NRG recorded a write-down of $58 million in the fourth
quarter of 2002, in addition to the $54 million previously recorded in 2002. At Dec. 31, 2002, the carrying value of the investment in Loy
Yang is approximately $72.9 million. Accumulated other comprehensive loss at Dec. 31, 2002, includes a reduction for foreign currency
translation losses of approximately $77 million related to Loy Yang. The foreign currency translation losses will continue to be included
as a component of accumulated other comprehensive loss until NRG commits to a plan to dispose of its investment.

other equity investment losses
Yorkshire Power Group Sale In August 2002, Xcel Energy announced it had sold its 5.25-percent interest in Yorkshire Power Group
Limited for $33 million to CE Electric UK. Xcel Energy and American Electric Power Co. each held a 50-percent interest in Yorkshire,
a UK retail electricity and 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. The loss is included in write-downs and disposal losses from investments on the Consolidated Statements of Operations.

4. nrg acquisition and restructuring plan

During 2002, Xcel Energy acquired all of the 26 percent of NRG shares not then owned by Xcel Energy through a tender offer and
merger involving a tax-free exchange of 0.50 shares of Xcel Energy common stock for each outstanding share of NRG common stock.
The transaction was completed on June 3, 2002.

The exchange of NRG common shares for Xcel Energy common shares was accounted for as a purchase. The 25,764,852 shares of Xcel
Energy stock issued were valued at $25.14 per share, based on the average market price of Xcel Energy shares for three days before and
after April 4, 2002, when the revised terms of the exchange were announced and recommended by the independent members of the NRG
board. Including other costs of acquisition, this resulted in a total purchase price to acquire NRG’s shares of approximately $656 million.

The process to allocate the purchase price to underlying interests in NRG assets and to determine fair values for the interests in assets
acquired resulted in approximately $62 million of amounts being allocated to fixed assets related to projects where the fair values were
in excess of carrying values, to prepaid pension assets and to other assets. The preliminary purchase price allocation is subject to change
as the final purchase price allocation and asset valuation process is completed.

In December 2001, Moody’s Investor Service (Moody’s) placed NRG’s long-term senior unsecured debt rating on review for possible
downgrade. In February 2002, in response to this threat to NRG’s investment grade rating, Xcel Energy announced a financial
improvement plan for NRG, which included an initial step of acquiring 100 percent of NRG through a tender offer and merger
involving a tax-free exchange of 0.50 shares of Xcel Energy common stock for each outstanding share of NRG common stock. The
transaction was completed on June 3, 2002. In addition, the initial plan included financial support to NRG from Xcel Energy, marketing
certain NRG generating assets for possible sale, canceling and deferring capital spending for NRG projects and combining certain of
NRG’s functions with Xcel Energy’s systems and organization. During 2002, Xcel Energy provided NRG with $500 million of cash
infusions. Throughout this period, Xcel Energy was in discussions with credit agencies and believed that its actions would be sufficient
to avoid a downgrade of NRG’s credit rating.

However, even with NRG’s efforts to avoid a downgrade, on July 26, 2002, Standard & Poor’s (S&P) downgraded NRG’s senior unsecured
bonds below investment grade, and, three days later, Moody’s also downgraded NRG’s senior unsecured debt rating below investment
grade. Over the next few months, NRG senior unsecured debt, as well as the secured NRG Northeast Generating LLC bonds, the secured
NRG South Central Generating LLC bonds and secured LSP Energy (Batesville) bonds were downgraded multiple times. After NRG
failed to make the payment obligations due under certain unsecured bond obligations on Sept. 16, 2002, both Moody’s and S&P lowered
their ratings on NRG’s unsecured bonds once again. Currently, unsecured bond obligations carry a rating of between CCC and D at S&P
and between Ca and C at Moody’s, depending on the specific debt issue.

page 60

xcel energy inc. and subsidiaries

notes to consolidated financial statements

Many of the corporate guarantees and commitments of NRG and its subsidiaries require that they be supported or replaced with letters
of credit or cash collateral within 5 to 30 days of a ratings downgrade below investment grade by Moody’s or S&P. As a result of the
multiple downgrades, NRG estimated that it would be required to post collateral of approximately $1.1 billion.

Starting in August 2002, NRG engaged in the preparation of a comprehensive business plan and forecast. The business plan detailed the
strategic merits and financial value of NRG’s projects and operations. It also anticipated that NRG would function independently from
Xcel Energy and thus all plans and efforts to combine certain functions of the companies were terminated. NRG utilized independent
electric revenue forecasts from an outside energy markets consulting firm to develop forecasted cash flow information included in the
business plan. NRG management concluded that the forecasted free cash flow available to NRG after servicing project-level obligations
would be insufficient to service recourse debt obligations. Based on this information and in consultation with Xcel Energy and its financial
advisor, NRG prepared and submitted a restructuring plan in November 2002 to various lenders, bondholders and other creditor groups
(collectively, NRG’s creditors) of NRG and its subsidiaries. The restructuring plan was expected to serve as a basis for negotiations with
NRG’s creditors in a financially restructured NRG.

The restructuring plan also included a proposal by Xcel Energy that in return for a release of any and all claims against Xcel Energy,
upon consummation of the restructuring, Xcel Energy would pay $300 million to NRG and surrender its equity ownership of NRG.

In mid-December 2002, the NRG bank steering committee submitted a counterproposal and in January 2003, the bondholder credit
committee issued its counterproposal to the NRG restructuring plan. The counterproposal would request substantial additional payments
by Xcel Energy. A new NRG restructuring proposal was presented to the creditors at the end of January 2003. A preliminary settlement
has been reached with NRG’s creditors. Since many of these conditions are not within Xcel Energy’s control, Xcel Energy cannot state
with certainty that the settlement will be effectuated. Nevertheless, Xcel Energy management is optimistic at this time that the settle-
ment will be implemented.

On March 26, 2003, Xcel Energy’s board of directors approved a tentative settlement with holders of most of NRG’s long-term notes
and the steering committee representing NRG’s bank lenders regarding alleged claims of such creditors against Xcel Energy, including
claims related to the support and capital subscription agreement between Xcel Energy and NRG dated May 29, 2002 (Support Agreement).
The settlement is subject to a variety of conditions as set forth below, including definitive documentation. The principal terms of the
settlement as of the date of this report were as follows:

Xcel Energy would pay up to $752 million to NRG to settle all claims of NRG and the claims of NRG against Xcel Energy, including
all claims under the Support Agreement.

$350 million would be paid at or shortly following the consummation of a restructuring of NRG’s debt through a bankruptcy proceeding.
It is expected that this payment would be made prior to year-end 2003. $50 million would be paid on Jan. 1, 2004, and all or any part of
such payment could be made, at Xcel Energy’s election, in Xcel Energy common stock. Up to $352 million would be paid on April 30, 2004,
except to the extent that Xcel Energy had not received at such time tax refunds equal to $352 million associated with the loss on its
investment in NRG. To the extent Xcel Energy had not received such refunds, the April 30 payment would be due on May 30, 2004.

$390 million of the Xcel Energy payments are contingent on receiving releases from NRG creditors. To the extent Xcel Energy does not
receive a release from an NRG creditor, Xcel Energy’s obligation to make $390 million of the payments would be reduced based on the
amount of the creditor’s claim against NRG. As noted below, however, the entire settlement is contingent upon Xcel Energy receiving
releases from at least 85 percent of the claims in various NRG creditor groups. As a result, it is not expected that Xcel Energy’s payment
obligations would be reduced by more than approximately $60 million. Any reduction would come from the Xcel Energy payment due
on April 30, 2004.

Upon the consummation of NRG’s debt restructuring through a bankruptcy proceeding, Xcel Energy’s exposure on any guarantees or
other credit supported obligations incurred by Xcel Energy for the benefit of NRG or any subsidiary would be terminated and any cash
collateral posted by Xcel Energy would be returned to it. The current amount of such cash collateral is approximately $11.5 million.

As part of the settlement with Xcel Energy, any intercompany claims of Xcel Energy against NRG or any subsidiary arising from the
provision of intercompany goods or services or the honoring of any guarantee will be paid in full in cash in the ordinary course except
that the agreed amount of such intercompany claims arising or accrued as of Jan. 31, 2003, will be reduced from approximately $55 million
as asserted by Xcel Energy to $13 million. The $13 million agreed amount is to be paid upon the consummation of NRG’s debt
restructuring with $3 million in cash and an unsecured promissory note of NRG on market terms in the principal amount of $10 million.

NRG and its direct and indirect subsidiaries would not be reconsolidated with Xcel Energy or any of its other affiliates for tax purposes
at any time after their June 2002 re-affiliation or treated as a party to or otherwise entitled to the benefits of any tax-sharing agreement
with Xcel Energy. Likewise, NRG would not be entitled to any tax benefits associated with the tax loss Xcel Energy expects to incur in
connection with the write-down of its investment in NRG.

xcel energy inc. and subsidiaries          page 61

notes to consolidated financial statements

Xcel Energy’s obligations under the tentative settlement, including its obligations to make the payments described previously, are
contingent upon, among other things, the following:

– definitive documentation, in form and substance satisfactory to the parties;
– between 50 percent and 100 percent of the claims represented by various NRG facilities or creditor groups (NRG Credit
Facilities) having executed an agreement, in form and substance satisfactory to Xcel Energy, to support the settlement;

– various stages of the implementation of the settlement occurring by dates currently being negotiated, with the consummation of

the settlement to occur by Sept. 30, 2003;

– the receipt of releases in favor of Xcel Energy by at least 85 percent of the claims represented by the NRG Credit Facilities;
– the receipt by Xcel Energy of all necessary regulatory approvals; and
– no downgrade prior to consummation of the settlement of any Xcel Energy credit rating from the level of such rating as of

March 25, 2003.

Based on the foreseeable effects of a settlement agreement with the major NRG noteholders and bank lenders and the tax effect of an
expected write-off of Xcel Energy’s investment in NRG, Xcel Energy would recognize the expected tax benefits of the write-off as of
Dec. 31, 2002. The tax benefit has been estimated at approximately $706 million. This benefit is based on the tax basis of Xcel Energy’s
investment in NRG.

Xcel Energy expects to claim a worthless stock deduction in 2003 on its investment. This would result in Xcel Energy having a net
operating loss for the year. Under current law, this 2003 net operating loss could be carried back two years for federal purposes. Xcel
Energy expects to file for a tax refund of approximately $355 million in first quarter 2004. This refund is based on a two-year carryback.
However, under the Bush administration’s new dividend tax proposal, the carryback could be one year, which would reduce the refund
to $125 million.

As to the remaining $351 million of expected tax benefits, Xcel Energy expects to eliminate or reduce estimated quarterly income tax
payments, beginning in 2003. The amount of cash freed up by the reduction in estimated tax payments would depend on Xcel Energy’s
taxable income.

Negotiations are ongoing. There can be no assurance that NRG creditors ultimately will accept any consensual restructuring plan, or
whether, in the interim, NRG lenders and bondholders will forbear from exercising any or all of the remedies available to them, including
acceleration of NRG’s indebtedness, commencement of an involuntary proceeding in bankruptcy and, in the case of a certain lender,
realization on the collateral for their indebtedness.

Throughout the restructuring process, NRG seeks to operate the business in a manner that NRG management believes will offer to
creditors similar protection as would be offered by a bankruptcy court. NRG attempts to preserve the enterprise value of the business
and to treat creditors within each creditor class without preference, unless otherwise agreed to by advisors to all potentially affected
creditors. By operating NRG within this framework, NRG desires to mitigate the risk that creditors will pursue involuntary bankruptcy
proceedings against NRG or its material subsidiaries.

Whether or not NRG reaches a consensual arrangement with NRG’s creditors, there is a substantial likelihood that NRG will be the
subject of a bankruptcy proceeding. If an agreement were reached with NRG’s Creditors on a restructuring plan, it is expected that
NRG would commence a Chapter 11 bankruptcy case and immediately seek approval of a prenegotiated plan of reorganization. Absent
an agreement with NRG’s Creditors and the continued forbearance by such creditors, NRG will be subject to substantial doubt as to its
ability to continue as a going concern and will likely be the subject of a voluntary or involuntary bankruptcy proceeding, which, due to
the lack of a prenegotiated plan of reorganization, would be expected to take an extended period of time to be resolved and may involve
claims against Xcel Energy under the equitable doctrine of substantive consolidation.

Potential NRG Bankruptcy A preliminary settlement agreement with NRG’s creditors on a comprehensive financial restructuring plan
that, among other things, addresses Xcel Energy’s continuing role and degree of ownership in NRG and obligations to NRG in a
restructured NRG has been reached. Following an agreement on the restructuring with NRG’s creditors and as described previously, it
is expected that NRG would commence a Chapter 11 bankruptcy proceeding and immediately seek approval of a prenegotiated plan
of reorganization. Absent an agreement with NRG’s creditors and the continued forbearance by such creditors, NRG will be subject to
substantial doubt as to its ability to continue as a going concern and will likely be the subject of a voluntary or involuntary bankruptcy
proceeding, which, due to the lack of a prenegotiated plan of reorganization, would be expected to take an extended period of time
to be resolved.

While it is an exception rather than the rule, especially where one of the companies involved is not in bankruptcy, the equitable doctrine
of substantive consolidation permits a bankruptcy court to disregard the separateness of related entities, consolidate and pool the entities’
assets and liabilities and treat them as though held and incurred by one entity where the interrelationship between the entities warrants
such consolidation. Xcel Energy believes that any effort to substantively consolidate Xcel Energy with NRG would be without merit.
However, it is possible that NRG or its creditors would attempt to advance such claims or other claims under piercing the corporate

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xcel energy inc. and subsidiaries

notes to consolidated financial statements

veil, alter ego or related theories should an NRG bankruptcy proceeding commence, particularly in the absence of a prenegotiated plan
of reorganization, and Xcel Energy cannot be certain how a bankruptcy court would resolve these issues. One of the creditors of an
NRG project, as previously discussed, has already filed involuntary bankruptcy proceedings against that project and has included claims
against both NRG and Xcel Energy. If a bankruptcy court were to allow substantive consolidation of Xcel Energy and NRG, it would
have a material adverse effect on Xcel Energy.

The accompanying Consolidated Financial Statements do not reflect any conditions or matters that would arise if NRG were in bankruptcy.

If NRG were to file for bankruptcy, and the necessary actions were taken by Xcel Energy to fully relinquish its effective control over
NRG, Xcel Energy anticipates that NRG would no longer be included in Xcel Energy’s consolidated financial statements, prospectively
from the date such actions were taken. Such de-consolidation of NRG would encompass a change in Xcel Energy’s accounting for
NRG to the equity method, under which Xcel Energy would continue to record its interest in NRG’s income or losses until Xcel
Energy’s investment in NRG (under the equity method) reached the level of obligations that Xcel Energy had either guaranteed on
behalf of NRG or was otherwise committed to in the form of financial assistance to NRG. Prior to completion of a bankruptcy
proceeding, a prenegotiated plan of reorganization or other settlement reached with NRG’s creditors would be the determining factors
in assessing whether a commitment to provide financial assistance to NRG existed at the time of de-consolidation.

At Dec. 31, 2002, Xcel Energy’s pro forma investment in NRG, calculated under the equity method if applied at that date, was a negative
$625 million. If the amount of guarantees or other financial assistance committed to NRG by Xcel Energy exceeded that level after
de-consolidation of NRG, then NRG’s losses would continue to be included in Xcel Energy’s results until the amount of negative
investment in NRG reaches the amount of guarantees and financial assistance committed to by Xcel Energy. As of Dec. 31, 2002,
the estimated guarantee exposure that Xcel Energy had related to NRG liabilities was $96 million, as discussed in Note 16, and
potential financial assistance was committed in the form of a support and capital subscription agreement pursuant to which Xcel
Energy agreed, under certain circumstances, to provide an additional $300 million contribution to NRG if the financial restructuring
plan discussed earlier is approved by NRG’s creditors. Additional commitments for financial assistance to NRG could be created in
2003 as Xcel Energy, NRG and NRG’s creditors continue to negotiate terms of a possible prenegotiated plan of reorganization to
resolve NRG’s financial difficulties.

In addition to the effects of NRG’s losses, Xcel Energy’s operating results and retained earnings in 2003 could also be affected by the
tax effects of any guarantees or financial commitments to NRG, if such income tax benefits were considered likely of realization in
the foreseeable future. The income tax benefits recorded in 2002 related to Xcel Energy’s investment in NRG, as discussed in Note 11
to the Consolidated Financial Statements, includes only the tax benefits related to cash and stock investments already made in NRG
at Dec. 31, 2002. Additional tax benefits could be recorded in 2003 at the time that such benefits are considered likely of realization,
when the payment of guarantees and other financial assistance to NRG become probable.

Xcel Energy believes that the ultimate resolutions of NRG’s financial difficulties and going-concern uncertainty will not affect Xcel
Energy’s ability to continue as a going concern. Xcel Energy is not dependent on cash flows from NRG, nor is Xcel Energy contingently
liable to creditors of NRG in an amount material to Xcel Energy’s liquidity. Xcel Energy believes that its cash flows from regulated utility
operations and anticipated financing capabilities will be sufficient to fund its non-NRG-related operating, investing and financing
requirements. Beyond these sources of liquidity, Xcel Energy believes it will have adequate access to additional debt and equity financing
that is not conditioned upon the outcome of NRG’s financial restructuring plan.

xcel energy inc. and subsidiaries          page 63

notes to consolidated financial statements

5. short-term borrowings 

Notes Payable and Commercial Paper Information regarding notes payable and commercial paper for the years ended Dec. 31, 2002
and 2001, is:

(Millions of dollars, except interest rates)

Notes payable to banks
Commercial paper
Total short-term debt
Weighted average interest rate at year-end

2002

$1,542
–
$1,542
4.33%

2001

$ 835
1,390
$2,225
3.41%

Credit Facilities As of Dec. 31, 2002, Xcel Energy had the following credit facilities available:

Xcel Energy
NSP-Minnesota
PSCo
SPS
Other subsidiaries

Maturity

Term

Credit Line

November 2005
August 2003
June 2003
February 2003
Various

5 years
364 days
364 days
364 days
Various

$400 million
$300 million
$530 million
$250 million
$ 55 million

The lines of credit provide short-term financing in the form of bank loans and letters of credit and, depending on credit ratings, provide
support for commercial paper borrowings. At Dec. 31, 2002, there were $399 million of loans outstanding under the Xcel Energy line of
credit and $88 million for PSCo. The borrowing rates under these lines of credit are based on the applicable London Interbank Offered
Rate (LIBOR) plus an applicable spread, a euro dollar rate margin and the amount of money borrowed. At Dec. 31, 2002, the weighted
average interest rate would have been 2.70 percent and 2.42 percent, respectively. See discussion of NRG short-term debt at Note 7.

On Jan. 22, 2003, Xcel Energy entered into an agreement with Perry Capital and King Street Capital to provide Xcel Energy with a
nine-month, $100-million term loan facility. The facility carries a 9-percent per annum coupon rate and fees for early termination,
prepayment and extensions within the nine-month period. Xcel Energy has no current need to draw on the facility, but sought the
additional liquidity to provide financing flexibility. Xcel Energy, absent SEC approval under PUHCA, can only draw on this facility
when its common equity exceeds 30 percent of total capitalization.

The SPS $250-million facility expired in February 2003 and was replaced with a $100-million unsecured, 364-day credit agreement.
The NSP-Minnesota and PSCo credit facilities are secured by first mortgages and first collateral trust bonds, respectively.

6. long-term debt

Except for SPS and other minor exclusions, all property of our utility subsidiaries is subject to the liens of their first mortgage indentures,
which are contracts between the companies and their bondholders. In addition, certain SPS payments under its pollution-control
obligations are pledged to secure obligations of the Red River Authority of Texas.

The utility subsidiaries’ first mortgage bond indentures provide for the ability to have sinking-fund requirements. These annual
sinking-fund requirements are 1 percent of the highest principal amount of the series of first mortgage bonds at any time outstanding.
Sinking-fund requirements at NSP-Wisconsin, PSCo and Cheyenne are $2.8 million and are for one series of first mortgage bonds
each. Such sinking-fund requirements may be satisfied with property additions or cash. NSP-Minnesota and SPS have no sinking-
fund requirements.

NSP-Minnesota’s 2011 series bonds are redeemable upon seven-days notice at the option of the bondholder. Because of the terms that
allow the holders to redeem these bonds on short notice, we include them in the current portion of long-term debt reported under current
liabilities on the balance sheets.

See discussion of NRG long-term debt at Note 7.

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

2003 $7,759 million
2004 $ 239 million
2005 $ 313 million
2006 $ 722 million
2007 $ 420 million

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xcel energy inc. and subsidiaries

notes to consolidated financial statements

7. nrg debt and capital leases

As of Dec. 31, 2002, NRG has failed to make scheduled payments on interest and/or principal on approximately $4 billion of its recourse
debt and is in default under the related debt instruments. These missed payments also have resulted in cross-defaults of numerous other
nonrecourse and limited recourse debt instruments of NRG. In addition to the missed debt payments, a significant amount of NRG’s
debt and other obligations contain terms that require that they be supported with letters of credit or cash collateral following a ratings
downgrade. As a result of the downgrades that NRG has experienced in 2002, NRG estimates that it is in default of its obligations to
post collateral ranging from $1.1 billion to $1.3 billion, principally to fund equity guarantees associated with its construction revolver
financing facility, to fund debt service reserves and other guarantees related to NRG projects and to fund trading operations. Absent an
agreement on a comprehensive restructuring plan, NRG will remain in default under its debt and other obligations because it does not
have sufficient funds to meet such requirements and obligations. As a result, the lenders will be able, if they choose, to seek to enforce their
remedies at any time, which would likely lead to a bankruptcy filing by NRG. There can be no assurance that NRG’s creditors ultimately
will accept any consensual restructuring plan, or that, in the interim, NRG’s lenders and bondholders will continue to forbear from
exercising any or all of the remedies available to them, including acceleration of NRG’s indebtedness, commencement of an involuntary
proceeding in bankruptcy and, in the case of certain lenders, realization on the collateral for their indebtedness. See Note 4 for discussion
of 2003 developments regarding NRG’s financial restructuring.

Pending the resolution of NRG’s credit contingencies and the timing of possible asset sales, a portion of NRG’s long-term debt obligations
has been classified as current liabilities for those long-term obligations that lenders have the ability to accelerate such debt within 12 months
of the balance sheet date.

long-term and short-term debt defaults
NRG and its subsidiaries had failed to timely make the following interest and/or principal payments on their indebtedness:

(Millions of dollars)
Debt

Recourse Debt (unsecured)
NRG Energy ROARS

NRG Energy senior notes

NRG Energy senior notes
NRG Energy senior notes
NRG Energy senior notes
NRG Energy senior notes
NRG Energy senior notes
NRG Energy senior notes
NRG Energy senior debentures (NRZ Equity Units)

NRG Energy senior notes
NRG Energy 364-day corporate revolving facility
NRG Energy 364-day corporate revolving facility

Nonrecourse Debt (secured)
NRG Northeast Generating LLC
NRG Northeast Generating LLC
NRG Northeast Generating LLC
NRG South Central Generating LLC

NRG South Central Generating LLC

Amount Issued

Rate

Maturity

Interest
Due

Principal
Due

Date
Due

$ 250.0
$ 250.0
$ 350.0
$ 350.0
$ 350.0
$ 500.0
$ 240.0
$ 300.0
$ 250.0
$ 340.0
$ 287.5
$ 287.5
$ 125.0
$1,000.0
$1,000.0

$ 320.0
$ 130.0
$ 300.0
$ 500.0
$ 500.0
$ 300.0

8.700%
8.700%
8.250%
8.250%
7.750%
8.625%
8.000%
7.500%
7.500%
6.750%
6.500%
6.500%
7.625%
various
various

3/15/2005
3/15/2005
9/15/2010
9/15/2010
4/1/2011
4/1/2031
11/1/2003
6/1/2009
6/15/2007
7/15/2006
5/16/2006
5/16/2006
2/1/2006
3/7/2003
3/7/2003

8.065% 12/15/2004
8.842%
6/15/2015
9.292% 12/15/2024
3/15/2016
8.962%
3/15/2016
8.962%
9/15/2024
9.479%

$10.9
$10.9
$14.4
$14.4
$13.6
$21.6
$ 9.6
$11.3
$ 9.4
$11.5
$ 4.7
$ 4.7
$ 4.8
$ 7.6
$18.6

$ 5.1
$ 5.7
$13.9
$20.2
$ 0.0
$14.2

$ 0.0
$ 0.0
$ 0.0
$ 0.0
$ 0.0
$ 0.0
$ 0.0
$ 0.0
$ 0.0
$ 0.0
$ 0.0
$ 0.0
$ 0.0
$ 0.0
$ 0.0

$53.5
$ 0.0
$ 0.0
$12.8
$12.8
$ 0.0

9/16/2002
3/17/2003
9/16/2002
3/17/2003
10/1/2002
10/1/2002
11/1/2002
12/1/2002
12/15/2002
1/15/2003
11/16/2002
2/17/2003
2/1/2003
9/30/2002
12/31/2002

12/15/2002
12/15/2002
12/15/2002
9/16/2002
3/17/2003
9/16/2002

These missed payments may have also resulted in cross-defaults of numerous other nonrecourse and limited recourse debt instruments
of NRG.

short-term debt
NRG had an unsecured, revolving line of credit of $1 billion, which terminated on March 7, 2003. At Dec. 31, 2002, NRG had a $1-billion
outstanding balance under this credit facility. NRG has failed to make interest payments when due. In addition, NRG violated both the
minimum net worth covenant and the minimum interest coverage ratio requirements of the facility. On Feb. 27, 2003, NRG received a
notice of default on the corporate revolver financing facility, rendering the debt immediately due and payable. The recourse revolving
credit facility matured on March 7, 2003, and the $1 billion drawn remains outstanding. Accordingly, the facility is in default.

NRG’s $125-million syndicated letter of credit facility contains terms, conditions and covenants that are substantially the same as those
in NRG’s $1-billion, 364-day revolving line of credit. As of Dec. 31, 2002, NRG violated both the minimum net worth covenant and

xcel energy inc. and subsidiaries          page 65

notes to consolidated financial statements

the minimum interest coverage ratio requirements of the facility. Accordingly, the facility is in default. NRG had $110 million and
$170 million in outstanding letters of credit as of Dec. 31, 2002 and 2001, respectively.

long-term debt – corporate debt
Equity Units and Debentures In 2001, NRG completed the sale of 11.5 million equity units for an initial price of $25 per unit. Each equity
unit initially consists of a corporate unit comprising a $25 principal amount of NRG’s senior debentures and an obligation to acquire shares
of NRG common stock no later than May 18, 2004, at a price ranging from between $27.00 and $32.94. Approximately $4.1 million of the
gross proceeds have been recorded as additional paid in capital to reflect the value of the obligation to purchase NRG’s common stock. As a
result of the merger by Xcel Energy of NRG, holders of the equity units are no longer obligated to purchase shares of NRG common stock
under the purchase contracts. Instead, holders of the equity units are now obligated to purchase a number of shares of Xcel Energy common
stock upon settlement of the purchase contracts equal to the adjusted “settlement rate” or the adjusted “early settlement rate” as applicable. As
a result of the short-form merger, the adjusted settlement rate is 0.4630, resulting in a settlement price of approximately $55 per Xcel Energy
common share, and the adjusted early settlement rate is 0.3795, resulting in a settlement price of approximately $65 per Xcel Energy
common share, subject to the terms and conditions of the purchase contracts set forth in a purchase contract agreement. In October 2002,
NRG announced it would not make the November 2002 quarterly interest payment on the 6.50-percent senior unsecured debentures due in
2006, which trade with the associated equity units. The 30-day grace period to make payment ended Dec. 16, 2002, and NRG did not make
payment. As a result, this issue is in default. In addition, NRG did not make the Feb. 17, 2003, quarterly interest payment. In the event of an
NRG bankruptcy, the obligation to purchase shares of Xcel Energy stock terminates.

Senior Unsecured Notes The NRG $125-million, $250-million, $300-million, $350-million and $240-million senior notes are unsecured
and are used to support equity requirements for projects acquired and in development. The interest is paid semi-annually. The 30-day grace
period to make payment related to these issues has passed. NRG did not make the required payments and is in default on these notes.

Remarketable or Redeemable Securities The $240-million NRG senior notes due Nov. 1, 2013, are remarketable or redeemable securities
(ROARS). Nov. 1, 2003, is the first remarketing date for these notes. Interest is payable semi-annually on May 1 and Nov. 1 of each
year through 2003, and then at intervals and interest rates as discussed in the indenture. On the remarketing date, the notes must
either be mandatorily tendered to and purchased by Credit Suisse Financial Products or mandatorily redeemed by NRG at prices discussed
in the indenture. The notes are unsecured debt that rank senior to all of NRG’s existing and future subordinated indebtedness. On
Oct. 16, 2002, NRG entered into a termination agreement with the agent that terminated the remarketing agreement. A termination
payment of $31.4 million due on Oct. 17, 2002, has not been paid.

In March 2000, an NRG sponsored non-consolidated pass-through trust issued $250 million of 8.70-percent certificates due March 15,
2005. Each certificate represents a fractional undivided beneficial interest in the assets of the trust. Interest is payable on the certificates
semi-annually on March 15 and Sept. 15 of each year through 2005. The sole assets of the trust consist of £160 million, approximately $250
million on the date of issuance, principal amount 7.97 percent Reset Senior Notes due March 15, 2020, issued by NRG. The Reset
Senior Notes were used principally to finance NRG’s acquisition of the Killingholme facility. Interest is payable semi-annually on the
Reset Senior Notes on March 15 and Sept. 15 through March 15, 2005, and then at intervals and interest rates established in a
remarketing process. If the Reset Senior Notes are not remarketed on March 15, 2005, they must be mandatorily redeemed by NRG on
such date. On Sept. 16, 2002, NRG Pass-through Trust I failed to make a $10.9-million interest payment due on the $250 million bonds,
as a consequence of NRG failing to pay interest due on £160 million of 7.97-percent debt. The 30-day grace period to make payment
related to this issue has passed and NRG did not make the required payments. NRG is in default on these bonds.

Audrain Capital Lease In connection with NRG’s acquisition of the Audrain facilities, NRG recognized a capital lease on its balance
sheet within long-term debt in the amount of $239.9 million, as of Dec. 31, 2002 and 2001. The capital lease obligation is recorded at
the net present value of the minimum lease obligation payable. The lease terminates in May 2023. During the term of the lease, only
interest payments are due. No principal is due until the end of the lease. In addition, NRG has recorded in notes receivable an amount
of approximately $239.9 million, which represents its investment in the bonds that the county of Audrain issued to finance the project.
During December 2002, NRG received a notice of a waiver of a $24.0-million interest payment due on the capital lease obligation.

long-term debt – subsidiary
NEO Corp. The various NEO notes are term loans. The loans are secured principally by long-term assets of NEO Landfill Gas collection
system. NEO Landfill Gas is required to maintain compliance with certain covenants primarily related to incurring debt, disposing of
the NEO Landfill Gas assets and affiliate transactions. On Oct. 30, 2002, NRG failed to make $3.1 million in payments under certain
non-operating interest acquisition agreements. As a result, NEO Corp., a direct, wholly owned subsidiary of NRG, and NEO Landfill
Gas, Inc., an indirect, wholly owned subsidiary of NRG, failed to make approximately $1.4 million in loan payments. Also, the subsidiaries
of NEO Corp. and NEO Landfill Gas, Inc. failed to make approximately $2 million in payments pursuant to various agreements. NRG
received an extension until November 2002 with respect to NEO Landfill Gas, Inc. to make payments under such agreements, and such
payments were made during the extension period. The payments relating to NEO Corp. were not made, and the loan was due and payable
on Dec. 20, 2002. A letter of credit was drawn to pay the NEO Corp. loan in full on Dec. 23, 2002. As of Dec. 31, 2002, NEO Landfill

page 66

xcel energy inc. and subsidiaries

notes to consolidated financial statements

Gas, Inc. was in default under the loan agreement dated July 6, 1998, due to the failure to meet the insurance requirements under the
loan document. On Jan. 30, 2003, NRG failed to make $2.7 million in payments under certain acquisition agreements. As a result,
NEO Landfill Gas, Inc. failed to make its payment due on Jan. 30, 2003, under the loan agreement and the subsidiaries of NEO
Landfill Gas failed to make their payments pursuant to various agreements.

Northeast Generating LLC In February 2000, NRG Northeast Generating LLC, an indirect, wholly owned subsidiary of NRG, issued
$750 million of project level senior secured bonds to refinance short-term project borrowings and for certain other purposes. The bonds
are jointly and severally guaranteed by each of NRG Northeast’s existing and future subsidiaries. The bonds are secured by a security
interest in NRG Northeast’s membership or other ownership interests in the guarantors and its rights under all intercompany notes
between NRG Northeast and the guarantors. In December 2002, NRG Northeast Generating failed to make $24.7-million interest and
$53.5-million principal payments. NRG Northeast Generating had a 15-day grace period to make payment. On Dec. 27, 2002, NRG
made the $24.7-million interest payment due on the NRG Northeast Generating bonds but failed to make the $53.5-million principal
payment. As a result, the payment default associated with its failure to make principal payments when they come due is currently in
effect. NRG also failed to make a debt service reserve account cash deposit within 30 days of a credit-rating downgrade in July 2002. In
addition, NRG Northeast Generating is also in default of its debt covenants because of the lapse of the 60-day grace period regarding the
necessary dismissal of an involuntary bankruptcy proceeding. For these reasons, NRG Northeast Generating is in default on these notes.

NRG South Central Generating LLC In March 2000, NRG South Central Generating LLC, an indirect, wholly owned subsidiary of
NRG, issued $800 million of senior secured bonds in a two-part offering to finance its acquisition of the Cajun generating facilities.
The bonds are secured by a security interest in NRG Central U.S. LLC’s and South Central Generating Holding LLC’s membership
interests in NRG South Central and NRG South Central’s membership interests in Louisiana Generating and all of the assets related
to the Cajun facilities, including its rights under a guarantor loan agreement and all inter-company notes between it and Louisiana
Generating, and a revenue account and a debt service reserve account. On Sept. 15, 2002, NRG South Central Generating missed a
$47-million principal and interest payment. The 15-day grace period to make payment related to this issue has passed, and NRG South
Central Generating did not make the required payments. In January 2003, the South Central Generating bondholders unilaterally withdrew
$35.6 million from the restricted revenue account, relating to the Sept. 15, 2002, interest payment and fees. On March 17, 2003, South
Central bondholders were paid $34.4 million due in relation to the semi-annual interest payment, and the $12.8 million principal payment
was deferred. NRG South Central remains in default on these notes.

Flinders Power Finance In September 2000, Flinders Power Finance Pty (Flinders Power), an Australian wholly owned subsidiary, entered
into a 12-year AUD $150-million promissory note (US $81.4 million at September 2000). As of Dec. 31, 2002, there remains $80.5 million
outstanding under this facility. In March 2002, Flinders Power entered into a 10-year AUD $165-million (US $85.4 million at March 2002)
floating rate promissory note for the purpose of refurbishing the Flinders Playford generating station. As of Dec. 31, 2002, Flinders Power
had drawn $18.7 million (AUD $33 million) of this facility. Upon NRG’s credit-rating downgrade in 2002, there existed a potential default
under these agreements related to the funding of reserve funds. Flinders continues to work with its lenders subsequent to the downgrade.

NRG Peaker Finance Company LLC In June 2002, NRG Peaker Finance Co. LLC (NRG Peaker), an indirect, wholly owned subsidiary
of NRG, completed the issuance of $325 million of Series A Floating Rate Senior Secured Bonds, due 2019. The bonds are secured by
a pledge of membership interests in NRG Peaker and a security interest in all of its assets, which initially consisted of notes evidencing
loans to the affiliate project owners. The project owners jointly and severally guaranteed the entire principal amount of the bonds
and interest on such principal amount. The project owner guarantees are secured by a pledge of the membership interest in three of five
project owners and a security interest in substantially all of the project owners’ assets related to the peaker projects, including equipment,
real property rights, contracts and permits. NRG has entered into a contingent guarantee agreement in favor of the collateral agent for
the benefit of the secured parties, under which it agreed to make payments to cover scheduled principal and interest payments on the
bonds and regularly scheduled payments under the interest rate swap agreement, to the extent that the net revenues from the peaker
projects are insufficient to make such payments, in specified circumstances. As a result of cross-default provisions, this facility is in
default. On Dec. 10, 2002, $16.0 million in interest, principal, and swap payments were made from restricted cash accounts. As a
result, $319.4 million in principal remains outstanding as of Dec. 31, 2002.

LSP-Pike Energy LLC LSP-Pike Energy LLC received a loan to construct its power generation facility in Pike County, Mississippi,
that was financed by the issuance of industrial revenue bonds (Series 2002). NRG Finance Co. I LLC, an affiliate of LSP-Pike Energy
LLC, purchased the Series 2002 bonds. These bonds are subject to a subordination agreement between NRG Finance Co. I LLC, as
purchaser, and LSP-Pike Energy LLC and Credit Suisse First Boston, as administrative agent to a senior claim. In the case of insolvency
or bankruptcy proceedings, or any receivership, liquidation, reorganization or other similar proceedings, and even in the event of any
proceedings for voluntary liquidation, dissolutions or other winding up of the company, the holders of the senior claims shall be entitled
to receive payment in full or cash equivalents of all principal, interest, charges and fees on all senior claims before the purchaser is entitled
to receive any payment on account of the principal of or interest on these bonds. As of Oct. 17, 2002, the United States Bankruptcy
Court for the Southern District of Mississippi granted an order of relief to the debtor under the U.S. bankruptcy laws, thus forcing
LSP-Pike Energy LLC into default and cessation of all benefits granted under the terms of the loan agreement and issuance of the bonds.

xcel energy inc. and subsidiaries          page 67

notes to consolidated financial statements

long-term debt – credit facilities
NRG has several credit facilities used for long-term financing:

(Thousands of dollars)
Facility

Revolving lines of credit
NRG Finance Co. I LLC

Term loan facilities
Mid-Atlantic
LSP Kendall Energy
Brazos Valley
McClain

Available
Line of Credit

Recourse
to NRG

Outstanding
End Date Dec. 31, 2002

Rate at
Dec. 31, 2002

$2,000,000

$580,000
$554,200
$180,000
$296,000

Yes

No
No
No
No

May 2006

$1,081,000

4.92%

November 2005
September 2005
June 2008
November 2006

$409,200
$495,800
$194,400
$157,300

3.30%
3.19%
4.41%
4.57%

NRG Financing Co. I LLC The NRG Finance Co. I LLC facility has been used to finance the acquisition, development and construction
of power generating plants located in the United States, and to finance the acquisition of turbines for such facilities. The facility is
nonrecourse to NRG other than its obligation to contribute equity at certain times in respect of projects and turbines financed under the
facility. NRG estimates the obligations to contribute equity to be approximately $819 million as of Dec. 31, 2002. At Dec. 31, 2002,
interest and fees due in September 2002 were not paid, and NRG has suspended required equity contributions to the projects. Supporting
construction and other contracts associated with NRG’s Pike and Nelson projects were violated by NRG in September and October 2002,
respectively. In November 2002, lenders to NRG accelerated the approximately $1.08 billion of debt under the construction revolver
facility, rendering the debt immediately due and payable. Thus, this facility is currently in default.

LSP Kendall Energy As part of NRG’s acquisition of the LS Power assets in January 2001, NRG, through its wholly owned subsidiary
LSP Kendall Energy LLC, has acquired a $554.2-million credit facility. On Jan. 10, 2003, NRG received a notice of default from LSP
Kendall’s lenders indicating that certain events of default have taken place. By issuing this notice of default, the lenders have preserved all
of their rights and remedies under the credit agreement and other credit documents. NRG is negotiating a waiver to this default notice
with the creditors to LSP Kendall.

Brazos Valley In June 2001, NRG, through its wholly owned subsidiaries Brazos Valley Energy LP and Brazos Valley Technology LP,
entered into a $180-million nonrecourse construction credit facility to fund the construction of the 600-megawatt Brazos Valley gas-fired,
combined-cycle merchant generation facility, located in Texas. On Jan. 31, 2003, NRG consented to the foreclosure of its Brazos Valley
project by its lenders. As consequence of foreclosure, NRG no longer has any interest in the Brazos Valley project. However, NRG may
be obligated to infuse additional capital to fund a debt service reserve account that had never been funded, and may be obligated to make
an equity infusion to satisfy a contingent equity agreement. As of Dec. 31, 2002, NRG recorded $24 million for the potential obligations.

McClain In August 2001, NRG entered into a 364-day term loan of up to $296 million. The credit facility was structured as a senior
unsecured loan and was partially nonrecourse to NRG. The proceeds were used to finance the McClain generating facility acquisition.
In November 2001, the credit facility was repaid from the proceeds of a $181.0-million term loan and $8.0-million working capital
facility entered into by NRG McClain LLC with Westdeutsche Landesbank Girozentrale, nonrecourse to NRG. On Sept. 17, 2002,
NRG McClain LLC received notice from the agent bank that the project loan was in default as a result of the downgrade of NRG and
of defaults on material obligations.

8. preferred stock

At Dec. 31, 2002, Xcel Energy had six series of preferred stock outstanding, which were callable at its option at prices ranging from
$102.00 to $103.75 per share plus accrued dividends. Xcel Energy can only pay dividends on its preferred stock from retained earnings
absent approval of the SEC under PUHCA. See Note 12 for a description of such restrictions.

The holders of the $3.60 series preferred stock are entitled to three votes for each share held. The holders of the other preferred stocks
are entitled to one vote per share. While dividends payable on the preferred stock of any series outstanding is in arrears in an amount
equal to four quarterly dividends, the holders of preferred stocks, voting as a class, are entitled to elect the smallest number of directors
necessary to constitute a majority of the board of directors, and the holders of common stock, voting as a class, are entitled to elect the
remaining directors.

page 68

xcel energy inc. and subsidiaries

notes to consolidated financial statements

The charters of some of Xcel Energy’s subsidiaries also authorize the issuance of preferred shares. However, at this time, there are no
such shares outstanding. This chart shows data for first- and second-tier subsidiaries:

Cheyenne Light, Fuel & Power Co.
Southwestern Public Service Co.
Public Service Co. of Colorado

Preferred
Shares
Authorized

1,000,000
10,000,000
10,000,000

Preferred
Shares
Value Outstanding

Par

$100.00
1.00
$
0.01
$

None
None
None

9. mandatorily redeemable preferred securities of subsidiary trusts

SPS Capital I, a wholly owned, special-purpose subsidiary trust of SPS, has $100 million of 7.85-percent trust preferred securities issued
and outstanding that mature in 2036. Distributions paid by the subsidiary trust on the preferred securities are financed through interest
payments on debentures issued by SPS and held by the subsidiary trust, which are eliminated in consolidation. The securities are redeemable
at the option of SPS after October 2001, at 100 percent of the principal amount plus accrued interest. Distributions and redemption
payments are guaranteed by SPS.

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

PSCo Capital Trust I, a wholly owned, special-purpose subsidiary trust of PSCo, has $194 million of 7.60-percent trust preferred
securities issued and outstanding that mature in 2038. Distributions paid by the subsidiary trust on the preferred securities are financed
through interest payments on debentures issued by PSCo and held by the subsidiary trust, which are eliminated in consolidation.
The securities are redeemable at the option of PSCo after May 2003 at 100 percent of the principal amount outstanding plus accrued
interest. Distributions and redemption payments are guaranteed by PSCo.

The mandatorily redeemable preferred securities of subsidiary trusts are consolidated in Xcel Energy’s Consolidated Balance Sheets.
Distributions paid to preferred security holders are reflected as a financing cost in the Consolidated Statements of Operations, along
with interest charges.

The investments by Xcel Energy’s subsidiaries in jointly owned plants and the related ownership percentages as of Dec. 31, 2002, are:

10. joint plant ownership

(Thousands of dollars)

NSP-Minnesota
Sherco Unit 3

PSCo
Hayden Unit 1
Hayden Unit 2
Hayden Common Facilities
Craig Units 1 and 2
Craig Common Facilities Units 1, 2 and 3
Transmission Facilities, including Substations

Total PSCo

NRG
McClain
Big Cajun II Unit 3
Conemaugh 
Keystone 

Total NRG 

Plant in
Service

Accumulated
Construction
Depreciation Work in Progress

Ownership % 

$612,643

$291,754

$ 943

59.0

$ 84,486
79,882
27,339
59,636
18,473
89,254
$359,070

$277,566
188,758
62,045
52,905
$581,274

$ 38,429
42,291
3,300
31,963
9,029
29,365
$154,377

$ 12,329
12,275
4,134
3,543
$ 32,281

$ 446
6
250
258
3,409
1,208
$5,577

$

–
244
766
5,039
$6,049

75.5
37.4
53.1
9.7
6.5–9.7
42.0–73.0

77.0
58.0
3.7
3.7

NSP-Minnesota is part owner of Sherco 3, an 860-megawatt, coal-fueled electric generating unit. NSP-Minnesota is the operating
agent under the joint ownership agreement. NSP-Minnesota’s share of operating expenses for Sherco 3 is included in the applicable
utility components of operating expenses. PSCo’s assets include approximately 320 megawatts of jointly owned generating capacity.
PSCo’s share of operating expenses and construction expenditures is included in the applicable utility components of operating expenses.

xcel energy inc. and subsidiaries          page 69

notes to consolidated financial statements

NRG’s share of operating expenses and construction expenditures is included in the applicable nonregulated components of operating
expenses. Each of the respective owners is responsible for the issuance of its own securities to finance its portion of the construction costs.

11. income taxes

As discussed in Note 1 to the Consolidated Financial Statements, the tax filing status of NRG for 2002 will change from filing as a
separate consolidated group, apart from the Xcel Energy consolidated group, to the NRG members filing on a stand-alone basis. On
a stand-alone basis, the NRG member companies do not have the ability to recognize all tax benefits that may ultimately accrue from
its losses incurred in 2002. NRG may have the ability to receive tax benefits for such losses in future periods as income is earned.

In consideration of the foreseeable effects of the NRG restructuring plan on Xcel Energy’s investment in NRG, Xcel Energy has recognized
the expected tax benefits from this investment as of Dec. 31, 2002. The tax benefit was estimated to be $706 million and was recorded at one
of Xcel Energy’s nonregulated intermediate holding companies. This benefit is based on the difference between the book and tax bases of
Xcel Energy’s investment in NRG.

The actual amount of tax benefit derived by Xcel Energy for its investment in NRG is dependent upon various factors, including certain
factors that may be affected by the terms of any financial restructuring agreement reached with NRG’s creditors. Similarly, the amount
and timing of tax benefits to be recorded by NRG, related to 2002 losses, is dependent on estimated future results of NRG.

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

Federal statutory rate
Increases (decreases) in tax from:

State income taxes, net of federal income tax benefit
Life insurance policies
Tax credits recognized
Equity income from unconsolidated affiliates
Income from foreign consolidated affiliates
Regulatory differences – utility plant items
Valuation allowance
Xcel Energy tax benefit on NRG
Nondeductible merger costs
Other – net

Total effective income tax rate
Extraordinary item
Effective income tax rate from continuing operations

Income taxes comprise the following expense (benefit) items:

(Thousands of dollars)

Current federal tax expense
Current state tax expense
Current foreign tax expense
Current tax credits
Deferred federal tax expense
Deferred state tax expense
Deferred foreign tax expense
Deferred investment tax credits
Income tax expense (benefit) excluding extraordinary items
Tax expense (benefit) on extraordinary items

Total income tax expense from continuing operations

2002

35.0%

5.6
1.1
1.5
0.8
1.8
(0.5)
(46.8)
30.7
–
(1.9)
27.3
–
27.3%

2001

35.0%

3.6
(2.0)
(6.9)
(1.7)
(6.0)
1.9
5.8
–
–
(0.5 )
29.2
(0.4)
28.8%

2000

35.0%

6.0
(2.5)
(10.7)
(2.3)
1.8
2.4
–
–
3.1
2.9
35.7
1.0
36.7%

2002

2001

2000

$ 114,273
21,724
18,973
(18,067)
(631,468)
(114,486)
(2,248)
(16,686)
(627,985)
–
$(627,985)

$373,710
26,927
10,988
(66,179)
(24,323)
18,702
4,529
(12,983)
331,371
4,807
$336,178

$205,472
63,428
1,693
(71,270)
103,033
12,547
(578)
(15,295)
299,030
(8,549)
$290,481

As of Dec. 31, 2001, Xcel Energy management intended to reinvest the earnings of NRG’s foreign operations to the extent the earnings
were subject to current U.S. income taxes. Accordingly, U.S. income taxes and foreign withholding taxes were not provided on a cumulative
amount of unremitted earnings of foreign subsidiaries of approximately $345 million at Dec. 31, 2001. As of Dec. 31, 2002, Xcel Energy
management has revised its strategy and no longer intends to indefinitely reinvest the full amount of earnings of NRG’s foreign operations.
However, no U.S. income tax benefit has been provided on the cumulative amount of unremitted losses of $339.7 million at Dec. 31, 2002,
due to the uncertainty of realization.

Xcel Energy management intends to indefinitely reinvest the earnings of the Argentina operations of Xcel Energy International and,
therefore, has not provided deferred taxes for the effects of currency devaluations.

page 70

xcel energy inc. and subsidiaries

notes to consolidated financial statements

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

(Thousands of dollars)

Deferred tax liabilities
Differences between book and tax basis of property
Regulatory assets
Partnership income/loss
Unrealized gains and losses on mark-to-market transactions
Tax benefit transfer leases
Employee benefits and other accrued liabilities
Other
Total deferred tax liabilities

Deferred tax assets
Xcel Energy benefit on NRG
Book write-down (impairment of assets)
Net operating loss carryforward
Differences between book and tax basis of contracts
Deferred investment tax credits
Regulatory liabilities
Unrealized gains and losses on mark-to-market transactions
Foreign tax loss carryforwards
Other
Total deferred tax assets
Less valuation allowance
Net deferred tax liability

2002

2001

$2,060,450
159,942
33,739
–
10,993
8,883
78,250
$2,352,257

$ 706,000
707,183
473,220
19,806
66,801
48,558
30,707
16,088
73,838
$2,142,201
1,077,047
$1,287,103

$2,083,965
155,587
53,955
9,348
14,765
16,559
66,538
$2,400,717

$

–
–
3,867
82,972
72,345
66,507
–
90,251
83,484
$ 399,426
66,622
$2,067,913

12. common stock and incentive stock plans

Common Stock and Equivalents In February 2002, Xcel Energy issued 23 million shares of common stock at $22.50 per share. In June
2002, Xcel Energy issued 25.7 million shares of common stock to complete its exchange offer for the publicly held stock of NRG. As
a result of these issuances, Xcel Energy had approximately 399 million shares outstanding on Dec. 31, 2002.

In November 2002, Xcel Energy issued $230 million of 7.5-percent convertible senior notes. The senior notes are convertible into shares
of Xcel Energy common stock at a conversion price of $12.33 per share. The conversion of $230 million in notes at a share price of
$12.33 would be the equivalent of approximately 18.7 million shares. However, due to losses experienced in 2002, the impact of the
convertible senior notes was antidilutive and, therefore, was not included in the common stock and equivalent calculation in 2002.

Other common stock equivalents included stock options, as discussed further, and NRG equity units. See discussion of NRG equity
units, which are convertible to Xcel Energy common stock, at Note 7. Due to the losses experienced in 2002, these equivalents were
also antidilutive and were not incorporated in the common stock and equivalents calculation in 2002.

The dilutive impacts of common stock equivalents affected earnings per share as follows for the years ending Dec. 31:

(Thousands of dollars, except per share amounts)

Basic EPS calculation
Earnings (loss) available for common
Weighted average common stock outstanding

Basic earnings per share

Diluted calculation
Earnings (loss) available for common
Adjustments for dilutive securities

Earnings (loss) for dilutive securities
Weighted average common stock outstanding
Adjustments for common stock equivalents

Weighted average common stock and equivalents
Diluted earnings per share

2002

2001

2000

$(2,222,232)
382,051
(5.82)

$

$(2,222,232)
–
$(2,222,232)
382,051
–
382,051
(5.82)

$

$790,725
342,952
2.31

$

$790,725
–
$790,725
342,952
790
343,742
2.30

$

$522,587
337,832
1.54

$

$522,587
–
$522,587
337,832
279
338,111
1.54

$

Incentive Stock Plans Xcel Energy and some of its subsidiaries have incentive compensation plans under which stock options and other
performance incentives are awarded to key employees. The weighted average number of common and potentially dilutive shares outstanding
used to calculate our earnings per share include the dilutive effect of stock options and other stock awards based on the treasury stock
method. The options normally have a term of 10 years and generally become exercisable from three to five years after grant date or upon
specified circumstances. The tables that follow include awards made by us and some of our predecessor companies, adjusted for the
merger stock exchange ratio, and are presented on an Xcel Energy share basis.

xcel energy inc. and subsidiaries          page 71

notes to consolidated financial statements

Activity in stock options and performance awards for the years ended Dec. 31:

(Awards in thousands)

Outstanding at beginning of year
Granted
Options adopted from NRG
Exercised
Forfeited
Expired
Outstanding at end of year
Exercisable at end of year

2002

2001

2000

Awards

15,214
–
3,328
(112)
(1,349)
(100)
16,981
8,993

Average
Price

$25.65
–
29.97
20.27
28.43
28.87
26.29
$24.78

Awards

14,259
2,581
–
(1,472)
(142)
(12)
15,214
7,154

Average
Price

$25.35
25.98
–
23.00
27.08
24.07
25.65
$24.78

Awards

8,490
6,980
–
(453)
(704)
(54)
14,259
8,221

Average
Price

$25.12
25.31
–
20.33
25.70
22.62
25.35
$24.46

At Dec. 31, 2002

Options outstanding:

Number outstanding
Weighted average remaining contractual life (years)
Weighted average exercise price

Options exercisable:

Number exercisable
Weighted average exercise price

$11.50 to $25.50

Range of Exercise Prices
$25.51 to $27.00

$27.01 to $63.60

4,449,827
4.7
$19.87

4,091,097
$20.17

7,878,856
7.3
$26.29

3,158,956
$26.46

4,652,424
7.4
$32.44

1,742,579
$32.57

Certain employees also may be awarded restricted stock under our incentive plans. We hold restricted stock until restrictions lapse,
generally from two to three years from the date of grant. We reinvest dividends on the shares we hold while restrictions are in place.
Restrictions also apply to the additional shares acquired through dividend reinvestment. Restricted shares have a value equal to the
market trading price of Xcel Energy’s stock at the grant date. We granted 50,083 restricted shares in 2002, when the grant-date market
price was $22.83, 21,774 restricted shares in 2001, when the grant-date market price was $26.06 and 58,690 restricted shares in 2000,
when the grant-date market price was $19.25. Compensation expense related to these awards was immaterial.

The NCE/NSP merger was a “change in control” under the NSP incentive plan, so all stock option and restricted stock awards under
that plan became fully vested and exercisable as of the merger date. The NCE/NSP merger was not a “change in control” under the NCE
incentive plans, so there was no accelerated vesting of stock options issued under them. When NCE and NSP merged, each outstanding
NCE stock option was converted to 1.55 Xcel Energy options.

We apply Accounting Principles Board Opinion No. 25 in accounting for our stock-based compensation and, accordingly, no compensation
cost is recognized for the issuance of stock options as the exercise price of the options equals the fair-market value of our common stock
at the date of grant. If we had used the SFAS No. 123 method of accounting, earnings would have been the same for 2002 and reduced
by approximately 1 cent per share for 2001 and 2 cents per share for 2000.

The weighted-average fair value of options granted, and the assumptions used to estimate such fair value on the date of grant using the
Black-Scholes Option Pricing Model, were as follows:

Weighted-average fair value per option share at grant date
Expected option life
Stock volatility
Risk-free interest rate
Dividend yield

* There were no options granted in 2002.

2002*

2001

2000

–
–
–
–
–

$2.13
3–5 years
18%
3.8–4.8%
4.9–5.8%

$2.57
3–5 years
15%
5.3–6.5%
5.4–7.5%

Common Stock Dividends Per Share Historically, we have paid quarterly dividends to our shareholders. For each quarter in 2001 and for
the first two quarters of 2002, we paid dividends to our shareholders of $0.375 per share. In the third and fourth quarters of 2002, we
paid dividends of $0.1875 per share. In making the decision to reduce the dividend, the board of directors considered several factors,
including the goal of funding customer growth in our core business through internal cash flow and reducing our reliance on debt and
equity financings. The board of directors also compared our dividend to its utility earnings and to the dividend payout of comparable
utilities. Dividends on our common stock are paid as declared by our board of directors.

Dividend and Other Capital-Related Restrictions 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. Due to 2002 losses incurred by NRG, retained earnings of Xcel

page 72

xcel energy inc. and subsidiaries

notes to consolidated financial statements

Energy were a deficit of $101 million at Dec. 31, 2002, and, accordingly, dividends cannot be declared until earnings in 2003 are sufficient
to eliminate this deficit or Xcel Energy is granted relief under the PUHCA. Xcel Energy has requested authorization from the SEC to
pay dividends out of paid-in capital up to $260 million until Sept. 30, 2003. Xcel Energy did not declare a dividend on its common stock
during the first quarter of 2003. It is not known when or if the SEC will act on this request.

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 (i) common stock
plus surplus divided by (ii) the sum of common stock plus surplus plus long-term debt. Based on this definition, our capitalization ratio
at Dec. 31, 2002, was 85 percent. Therefore, the restrictions do not place any effective limit on our 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 our common stock.

In addition, NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy,
the holder of its common stock. Even with these restrictions, NSP-Minnesota could have paid more than $825 million in additional
cash dividends on common stock at Dec. 31, 2002.

Under PUHCA, Xcel Energy is also restricted from financing activities when its common equity to total capitalization ratio is less than
30 percent. As a result of significant asset impairments at NRG, Xcel Energy’s common equity ratio fell below 30 percent during 2002.
However, the SEC approved Xcel Energy’s request to allow certain financing transactions through March 31, 2003, so long as its common
equity ratio, as reported in its most recent quarterly or annual report with the SEC and as adjusted for pending subsequent items that
affect capitalization, was at least 24 percent of its total capitalization. At Dec. 31, 2002, and as adjusted for subsequent items that affect
capitalization, Xcel Energy’s common equity ratio was 23 percent of its total capitalization. As a result, Xcel Energy could not finance at
Dec. 31, 2002, absent SEC approval.

Stockholder Protection Rights Agreement In June 2001, Xcel Energy adopted a Stockholder Protection Rights Agreement. Each share of
Xcel Energy’s common stock includes one shareholder protection right. Under the agreement’s principal provision, if any person or group
acquires 15 percent or more of Xcel Energy’s outstanding common stock, all other shareholders of Xcel Energy would be entitled to buy,
for the exercise price of $95 per right, common stock of Xcel Energy having a market value equal to twice the exercise price, thereby
substantially diluting the acquiring person’s or group’s investment. The rights may cause substantial dilution to a person or group that
acquires 15 percent or more of Xcel Energy’s common stock. The rights should not interfere with a transaction that is in the best interests
of Xcel Energy and its shareholders because the rights can be redeemed prior to a triggering event for $0.01 per right.

13. benefit plans and other postretirement benefits 

Xcel Energy offers various benefit plans to its benefit employees. Approximately 51 percent of benefit employees are represented by several
local labor unions under several collective-bargaining agreements. At Dec. 31, 2002, NSP-Minnesota had 2,246 and NSP-Wisconsin had
419 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2004. PSCo had 2,193 bargaining
employees covered under a collective-bargaining agreement, which expires in May 2003. SPS had 757 bargaining employees covered under
a collective-bargaining agreement, which expires in October 2005.

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

Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial
reporting purposes, subject to the limitations of applicable employee benefit and tax laws. Plan assets principally consist of the common stock
of public companies, corporate bonds and U.S. government securities. The target range for our pension asset allocation is 75 to 80 percent
with equity investments, 5 to 10 percent with fixed income investments, no cash investments and 10 to 15 percent with nontraditional
investments, such as real estate and timber ventures. At Dec. 31, 2002, the actual pension portfolio mix was 68 percent equity, 16 percent
fixed income, 4 percent cash investments and 12 percent nontraditional investments.

xcel energy inc. and subsidiaries          page 73

notes to consolidated financial statements

A comparison of the actuarially computed pension benefit obligation and plan assets, on a combined basis, is presented in the following table.

(Thousands of dollars)

Change in Benefit Obligation
Obligation at Jan. 1
Service cost
Interest cost
Acquisitions
Plan amendments
Actuarial loss
Settlements
Special termination benefits
Benefit payments
Obligation at Dec. 31

Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1
Actual return on plan assets
Employer contributions – acquisitions
Settlements
Benefit payments
Fair value of plan assets at Dec. 31

Funded Status of Plans at Dec. 31
Net asset
Unrecognized transition asset
Unrecognized prior service cost
Unrecognized (gain) loss
Net pension amounts recognized on Consolidated Balance Sheets

Prepaid pension asset recorded
Intangible asset recorded – prior service costs
Minimum pension liability recorded
Accumulated other comprehensive income recorded – pretax

Significant Assumptions
Discount rate for year-end valuation
Expected average long-term increase in compensation level
Expected average long-term rate of return on assets

2002

2001

$2,409,186
65,649
172,377
7,848
3,903
65,763
(994)
4,445
(222,601)
$2,505,576

$2,254,138
57,521
172,159
–
2,284
108,754
–
–
(185,670)
$2,409,186

$3,267,586
(404,940)
912
(994)
(222,601)
$2,639,963

$3,689,157
(235,901)
–
–
(185,670)
$3,267,586

$ 134,387
(2,003)
224,651
182,927
$ 539,962

$ 466,229
$
6,943
$ (106,897)
$ 173,687

$ 858,400
(9,317)
242,313
(712,571)
$ 378,825

$ 378,825
–
$
–
$
–
$

6.75%
4.00%
9.50%

7.25%
4.50%
9.50%

The discount rate and compensation increase assumptions above affect the succeeding year’s pension costs. The rate of return assumption
affects the current year’s pension cost. The return assumption used for 2003 pension cost calculations will be 9.25 percent. Pension costs
include an expected return impact for the current year that may differ from actual investment performance in the plan. The cost calculation
uses a market-related valuation of pension assets, which reduces year-to-year volatility by recognizing the differences between assumed
and actual investment returns over a five-year period.

NRG offers another noncontributory, defined benefit pension plan sponsored by one of its affiliates. For the year ended Dec. 31, 2002,
the total assets of this plan were $20 million, and its benefit obligation was $30 million. The pension liability recorded by NRG for this
plan was $12 million, and its annual pension cost was $2 million.

During 2002, one of Xcel Energy’s pension plans, other than the NRG plan just described, became underfunded, with projected benefit
obligations of $590 million exceeding plan assets of $452 million on Dec. 31, 2002. All other Xcel Energy plans, excluding the NRG plan
just described, in the aggregate had plan assets of $2,188 million and projected benefit obligations of $1,916 million on Dec. 31, 2002. A
minimum pension liability of $107 million was recorded related to the underfunded plan as of that date. A corresponding reduction in
Accumulated Other Comprehensive Income, a component of Stockholders’ Equity, was also recorded by Xcel Energy, as previously
recorded prepaid pension assets were reduced to record the minimum liability. Net of the related deferred income tax effects of the
adjustments, total Stockholders’ Equity was reduced by $108 million at Dec. 31, 2002, due to the minimum pension liability for the
underfunded plan.

page 74

xcel energy inc. and subsidiaries

notes to consolidated financial statements

The components of net periodic pension cost (credit) are:

(Thousands of dollars)

Service cost
Interest cost
Expected return on plan assets
Curtailment
Amortization of transition asset
Amortization of prior service cost
Amortization of net gain

Net periodic pension cost (credit) under SFAS No. 87

Credits not recognized due to effects of regulation

Net benefit cost (credit) recognized for financial reporting

2002

2001

2000

$ 65,649
172,377
(339,932)
–
(7,314)
22,663
(69,264)
$(155,821)
71,928
$ (83,893)

$ 57,521
172,159
(325,635)
1,121
(7,314)
20,835
(72,413)
$(153,726)
76,509
$ (77,217)

$ 59,066
172,063
(292,580)
–
(7,314)
19,197
(60,676)
$(110,244)
49,697
$ (60,547)

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

Defined Contribution Plans Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees.
Total contributions to these plans were approximately $23 million in 2002, $29 million in 2001 and $24 million in 2000.

Until May 6, 2002, Xcel Energy had a leveraged employee stock ownership plan (ESOP) that covered substantially all employees of
NSP-Minnesota and NSP-Wisconsin. Xcel Energy made contributions to this noncontributory, defined contribution plan to the extent
it realized tax savings from dividends paid on certain ESOP shares. ESOP contributions had no material effect on Xcel Energy earnings
because the contributions were essentially offset by the tax savings provided by the dividends paid on ESOP shares. Xcel Energy allocated
leveraged ESOP shares to participants when it repaid ESOP loans with dividends on stock held by the ESOP.

In May 2002, the ESOP was terminated and its assets were combined into the Xcel Energy retirement savings 401(k) plan. Starting with
the 2003 plan year, the ESOP component of the 401(k) plan will no longer be leveraged.

Xcel Energy’s leveraged ESOP held no shares of Xcel Energy common stock at the end of 2002, 10.7 million shares of Xcel Energy
common stock at May 6, 2002, 10.5 million shares of Xcel Energy common stock at the end of 2001 and 12 million shares of Xcel
Energy common stock at the end of 2000. Xcel Energy excluded the following average number of uncommitted leveraged ESOP shares
from earnings per share calculations: 0.7 million in 2002, 0.9 million in 2001 and 0.7 million in 2000. On Nov. 19, 2002, Xcel Energy
paid off all of the ESOP loans. All uncommitted ESOP shares were released and will be used by Xcel Energy for the 2002 employer
matching contribution to its 401(k) plan.

Postretirement Health Care Benefits Xcel Energy has contributory health and welfare benefit plans that provide health care and death
benefits to most Xcel Energy retirees. The former NSP discontinued contributing toward health care benefits for nonbargaining
employees retiring after 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin who retired after 1999. However,
employees of the former NCE who retired in 2002 continue to receive employer-subsidized health care benefits. Employees of the
former NSP who retired after 1998 are eligible to participate in the Xcel Energy health care program with no employer subsidy.

In conjunction with the 1993 adoption of SFAS No. 106 – “Employers’ Accounting for Postretirement Benefits Other Than Pension,” Xcel
Energy elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.

Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued benefit
costs under SFAS No. 106. PSCo transitioned to full accrual accounting for SFAS No. 106 costs between 1993 and 1997, consistent
with the accounting requirements for rate-regulated enterprises. The Colorado jurisdictional SFAS No. 106 costs deferred during the
transition period are being amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012. NSP-Minnesota
also transitioned to full accrual accounting for SFAS No. 106 costs, with regulatory differences fully amortized prior to 1997.

Certain state agencies that regulate Xcel Energy’s utility subsidiaries have also issued guidelines related to the funding of SFAS No. 106
costs. SPS is required to fund SFAS No. 106 costs for Texas and New Mexico jurisdictional amounts collected in rates, and PSCo is required
to fund SFAS No. 106 costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. Minnesota
and Wisconsin retail regulators required external funding of accrued SFAS No. 106 costs to the extent such funding is tax advantaged. Plan
assets held in external funding trusts principally consist of investments in equity mutual funds, fixed-income securities and cash equivalents.

xcel energy inc. and subsidiaries          page 75

notes to consolidated financial statements

A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy postretirement health care plans that benefit
employees of its utility subsidiaries is presented in the following table:

(Thousands of dollars)

Change in Benefit Obligation
Obligation at Jan. 1
Service cost
Interest cost
Acquisitions
Plan amendments
Plan participants’ contributions
Actuarial loss
Special termination benefits
Benefit payments
Obligation at Dec. 31

Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1
Actual return on plan assets
Plan participants’ contributions
Employer contributions
Benefit payments
Fair value of plan assets at Dec. 31

Funded Status at Dec. 31
Net obligation
Unrecognized transition asset (obligation)
Unrecognized prior service cost
Unrecognized gain (loss)
Accrued benefit liability recorded

Significant Assumptions
Discount rate for year-end valuation
Expected average long-term rate of return on assets (pretax)

2002

2001

$687,455
7,173
50,135
773
–
5,755
61,276
(173)
(44,419)
$767,975

$242,803
(13,632)
5,755
60,476
(44,419)
$250,983

$516,992
(169,328)
10,904
(206,601)
$151,967

$576,727
6,160
46,579
3,212
(278)
3,517
100,386
–
(48,848)
$687,455

$223,266
(3,701)
3,517
68,569
(48,848)
$242,803

$444,652
(186,099)
12,812
(134,225)
$137,140

6.75%
8.0–9.0%

7.25%
9.0%

The assumed health care cost trend rate for 2002 for most Xcel Energy plans is approximately 8 percent, decreasing gradually to 5.5 percent
in 2007 and remaining level thereafter. The assumed health care cost trend rate for 2002 for plans of four of NRG’s affiliates is approximately
12 percent, decreasing gradually to 5.5 percent in 2009 and remaining level thereafter. A 1-percent change in the assumed health care cost
trend rate would have the following effects:

(Thousands of dollars)

1-percent increase in APBO components at Dec. 31, 2002
1-percent decrease in APBO components at Dec. 31, 2002
1-percent increase in service and interest components of the net periodic cost
1-percent decrease in service and interest components of the net periodic cost

The components of net periodic postretirement benefit cost are:

(Thousands of dollars)

Service cost
Interest cost
Expected return on plan assets
Amortization of transition obligation
Amortization of prior service cost (credit)
Amortization of net loss (gain)

Net periodic postretirement benefit cost (credit) under SFAS No. 106

Additional cost recognized due to effects of regulation

Net cost recognized for financial reporting

$ 79,028
$(65,755)
$ 6,285
$ (5,181)

2002

2001

2000

$  7,173
50,135
(21,030)
16,771
(1,130)
5,380
57,299
4,043
$61,342

$ 6,160
46,579
(18,920)
16,771
(1,235)
1,457
50,812
3,738
$54,550

$ 5,679
43,477
(17,902)
16,773
(1,211)
915
47,731
6,641
$54,372

page 76

xcel energy inc. and subsidiaries

notes to consolidated financial statements

14. equity investments

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

A summary of Xcel Energy’s significant equity method investments is listed in the following table:

Name

Loy Yang Power A
Gladstone Power Station
MIBRAG GmbH
West Coast Power
Lanco Kondapalli Power (1)
Rocky Road Power
Schkopau
ECK Generating (1)
Commonwealth Atlantic
Mustang
Quixx Linden L.P.
Borger Energy L.P.
Various affordable housing 
limited partnerships

(1) Pending disposition at Dec. 31, 2002

Entity Form

Partnership
Joint Venture
Partnership
Partnership
Partnership
Partnership
Tenants in Common
Partnership

Joint Venture
General/Limited Partnership
General/Limited Partnership

Xcel Energy
Owner Functions

Geographic
Area

Dec. 31, 2002
Economic Interest

None
Operator
None
Operator
Operator
Operator
None
Operator

None
Operator
Operator

Australia
Australia
Europe
USA
India
USA
Europe
Czech Republic
USA
USA
USA
USA

25.37%
37.50%
50.00%
50.00%
30.00%
50.00%
41.67%
44.50%
50.00%
50.00%
50.00%
45.00%

Limited Partnerships

Various

USA

20.00%–99.99%

The following table summarizes financial information for these projects, including interests owned by Xcel Energy and other parties for
the years ended Dec. 31:

results of operations
(Millions of dollars)

Operating revenues
Operating income (loss)
Net income (loss)
Xcel Energy’s equity earnings of unconsolidated affiliates

financial position
(Millions of dollars)

Current assets
Other assets

Total assets
Current liabilities
Other liabilities
Equity

Total liabilities and equity

Xcel Energy’s share of undistributed retained earnings

Xcel Energy equity in underlying net assets
Difference – other than temporary write-downs, capitalized project costs and other
Xcel Energy’s investment in unconsolidated affiliates (per balance sheet)

2002

$2,516
$ 137
$ 111
72
$

2001

$3,583
$ 442
$ 422
$ 217

2002

$1,102
7,155
$8,257
$1,108
4,087
3,062
$8,257
$ 466

$1,285
(284)
$1,001

2000

$4,664
$ 464
$ 447
$ 183

2001

$1,478
7,396
$8,874
$1,229
4,841
2,804
$8,874
$ 449

$1,099
98
$1,197

West Coast Power In 2001, Xcel Energy had a significant investment in West Coast Power, LLC, through NRG, as defined by
applicable SEC regulations, and accounted for its investments using the equity method. The following is summarized pretax financial
information for West Coast Power:

results of operations
(Millions of dollars)

Operating revenues
Operating income (loss)
Net income (loss)

2001

$1,562
$ 345
$ 326

xcel energy inc. and subsidiaries          page 77

notes to consolidated financial statements

financial position
(Millions of dollars)

Current assets
Other assets

Total assets
Current liabilities
Other liabilities
Equity

Total liabilities and equity

2001

$ 401
659
$1,060
$ 138
269
653
$1,060

Yorkshire Power During February 2001, Xcel Energy reached an agreement to sell the majority of its investment in Yorkshire Power to
Innogy Holdings plc. As a result of this sales agreement, Xcel Energy did not record any equity earnings from Yorkshire Power after
January 2001. In April 2001, Xcel Energy closed the sale of Yorkshire Power. Xcel Energy had retained an interest of approximately
5.25 percent in Yorkshire Power to comply with pooling-of-interests accounting requirements associated with the merger of NSP and
NCE in 2000. Xcel Energy received approximately $366 million for the sale, which approximated the book value of Xcel Energy’s
investment. On Aug. 28, 2002, Xcel Energy sold its remaining 5.25-percent interest in Yorkshire Power at slightly less than book value.

15. extraordinary items 

SPS In the second quarter of 2000, SPS discontinued regulatory accounting under SFAS No. 71 for the generation portion of its business
due to the issuance of a written order by the Public Utility Commission of Texas (PUCT) in May 2000, addressing the implementation
of electric utility restructuring. SPS’ transmission and distribution business continued to meet the requirements of SFAS No. 71, as that
business was expected to remain regulated. During the second quarter of 2000, SPS wrote off its generation-related regulatory assets and
other deferred costs, totaling approximately $19.3 million. This resulted in an after-tax extraordinary charge of approximately $13.7 million.
During the third quarter of 2000, SPS recorded an extraordinary charge of $8.2 million before tax, or $5.3 million after tax, related to the
tender offer and defeasance of first mortgage bonds. The first mortgage bonds were defeased to facilitate the legal separation of generation,
transmission and distribution assets, which was expected to eventually occur in 2001 under restructuring requirements in effect in 2000.

In March 2001, the state of New Mexico enacted legislation that amended its Electric Utility Restructuring Act of 1999 and delayed
customer choice until 2007. SPS has requested recovery of its costs incurred to prepare for customer choice in New Mexico. A decision
on this and other matters is pending before the New Mexico Public Regulation Commission. SPS expects to receive future regulatory
recovery of these costs.

In June 2001, the governor of Texas signed legislation postponing the deregulation and restructuring of SPS until at least 2007. This
legislation amended the 1999 legislation, Senate Bill No. 7 (SB-7), which provided for retail electric competition beginning in Texas in
January 2002. Under the amended legislation, prior PUCT orders issued in connection with the restructuring of SPS are considered null
and void. In addition, under the new legislation, SPS is entitled to recover all reasonable and necessary expenditures made or incurred
before Sept. 1, 2001, to comply with SB-7.

As a result of these recent legislative developments, SPS reapplied the provisions of SFAS No. 71 for its generation business during the
second quarter of 2001. More than 95 percent of SPS’ retail electric revenues are from operations in Texas and New Mexico. Because
of the delays to electric restructuring passed by Texas and New Mexico, SPS’ previous plans to implement restructuring, including the
divestiture of generation assets, have been abandoned. Accordingly, SPS will now continue to be subject to rate regulation under traditional
cost-of-service regulation, consistent with its past accounting and ratemaking practices for the foreseeable future, until at least 2007.

During the fourth quarter of 2001, SPS completed a $500-million, medium-term debt financing with the proceeds used to reduce
short-term borrowings that had resulted from the 2000 defeasance. In its regulatory filings and communications, SPS proposed to
amortize its defeasance costs over the five-year life of the refinancing, consistent with historical ratemaking, and has requested incremental
rate recovery of $25 million of other restructuring costs in Texas and New Mexico. These nonfinancing restructuring costs have been
deferred and are being amortized consistent with rate recovery. Based on these 2001 events, management’s expectation of rate recovery
of prudently incurred costs and the corresponding reduced uncertainty surrounding the financial impacts of the delay in restructuring,
SPS restored certain regulatory assets totaling $17.6 million as of Dec. 31, 2001, and reported related after-tax extraordinary income
of $11.8 million, or 3 cents per share. Regulatory assets previously written off in 2000 were restored only for items currently being
recovered in rates and items where future rate recovery is considered probable.

PSCo During 2001, PSCo’s subsidiary, 1480 Welton, Inc., redeemed its long-term debt and in doing so incurred redemption premiums
and other costs of $2.5 million, or $1.5 million after tax. These items are reported as an Extraordinary Item on Xcel Energy’s Consolidated
Statement of Operations.

page 78

xcel energy inc. and subsidiaries

notes to consolidated financial statements

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

16. financial instruments

(Thousands of dollars)

Mandatorily redeemable preferred securities of subsidiary trusts
Long-term investments
Notes receivable, including current portion
Long-term debt, including current portion

2002

2001

Carrying
Amount

494,000
$
653,208
$
$
996,167
$14,306,509

Fair Value

463,348
$
651,443
$
$
996,167
$12,172,059

Carrying
Amount

494,000
$
619,976
$
$
782,079
$11,948,527

Fair Value 

486,270
$
620,703
$
$
782,079
$11,955,741

The carrying amount of cash, cash equivalents and short-term investments approximates fair value because of the short maturity of those
instruments. The fair values of Xcel Energy’s long-term investments, mainly debt securities in an external nuclear decommissioning
fund, are estimated based on quoted market prices for those or similar investments. The fair value of notes receivable is based on expected
future cash flows discounted at market interest rates. The balance in notes receivable consists primarily of fixed rate, from 4.75 to
19.5 percent, and variable rate notes that mature between 2003 and 2024. Notes receivable include a $366-million direct financing lease
related to a long-term sales agreement for NRG’s Schkopau project, and other notes related to projects at NRG that are generally
secured by equity interests in partnerships and joint ventures. The fair value of Xcel Energy’s long-term debt and the mandatorily
redeemable preferred securities are estimated based on the quoted market prices for the same or similar issues, or the current rates for debt
of the same remaining maturities and credit quality.

The fair value estimates presented are based on information available to management as of Dec. 31, 2002 and 2001. These fair value
estimates have not been comprehensively revalued for purposes of these Consolidated Financial Statements since that date, and current
estimates of fair values may differ significantly from the amounts presented herein.

guarantees
Xcel Energy provides various guarantees and bond indemnities supporting certain of its subsidiaries. The guarantees issued by Xcel Energy
guarantee payment or performance by its subsidiaries under specified agreements or transactions. As a result, Xcel Energy’s exposure
under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of
the guarantees issued by Xcel Energy limit the exposure of Xcel Energy to a maximum amount stated in the guarantees. Unless otherwise
indicated below, the guarantees require no liability to be recorded, contain no recourse provisions and require no collateral. On Dec. 31, 2002,
Xcel Energy had the following amount of guarantee and exposure under these guarantees:

xcel energy inc. and subsidiaries          page 79

notes to consolidated financial statements

(Millions of dollars)
Nature of Guarantee

Guarantee performance 
and payment of surety 
bonds for itself and 
its subsidiaries

Guarantee performance 
and payment of surety
bonds for those subsidiaries

Guarantees made to facilitate  

e prime’s natural gas acquisition,
marketing and trading operations

Guarantees for NRG liabilities 

associated with power marketing 
obligations, fuel purchasing 
transactions and hedging activities

Guarantee of payment of notes issued 

by Guardian Pipeline, LLC, of which 
Viking is one of three partners

Two guarantees benefiting Cheyenne  
to guarantee the payment obligations 
under gas and power purchase agreements

Construction contract performance 
guarantee of Utility Engineering 
subsidiaries 

Guarantee for obligations of a 
customer in connection with 
an electric sale agreement 

Guarantees related to energy  

conservation projects in which 
Planergy has guaranteed certain 
energy savings to the customer

Guarantee for payments related to 
energy or financial transactions 
for XERS Inc., a nonregulated 
subsidiary of Xcel Energy

Guarantee of 
collection of
receivables sold
to a third party

Combination of guarantees 

benefiting various Xcel Energy 
subsidiaries

Guarantor

Guarantee
Amount

Current
Exposure

Term or
Expiration

Triggering
Event
Requiring
Date Performance

Assets
Held as
Collateral

Xcel Energy (d)

$342.7 

$5.6

Various subsidiaries (e)

$493.8 

$116.0 

2003, 2004
2005, 2007
and 2012

2003, 2004
and 2005

Xcel Energy

$264.0 

$88.0 

Continuous

Xcel Energy

$219.5 

Latest 
expiration is
$96.3  Dec. 31, 2003

Xcel Energy

$60.0

$60.0

Terminated
Jan. 17, 2003

Xcel Energy

$26.5 

$1.7 

2011 and 2013

Xcel Energy

$25.0

$25.0

July 1, 2003

SPS (f )

$17.7 

$11.0 

Xcel Energy

$26.7 

$26.7 

September
2003

Expired
Jan. 1, 2003

(b)

(b)

(a)

(a)

(a)

(a)

(c)

(a)

$10.0

N/A

N/A

N/A

N/A

N/A

N/A

Electric
transmission
system

N/A

N/A

Xcel Energy

$11.1 

$4.1 

Continuous

(a)

N/A

NSP-Minnesota

$6.2 

$6.2

Latest
expiration
in 2007

Xcel Energy

$16.4 

$5.4 

Continuous

Security interest
in underlying
receivable
agreements

N/A

(a)

(a)

(a) Nonperformance and/or nonpayment
(b) Failure of Xcel Energy or one of its subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement

between Xcel Energy and the various surety companies, the surety companies have the discretion to demand that collateral be posted.

(c) Failure to meet emission compliance at relevant facility
(d) $5.6-million exposure is related to $265 million of performance bonds associated with a single construction project in which Utility Engineering is participating.
On Dec. 31, 2002, this project was 93-percent complete, and is expected to be fully complete in April 2003. An estimate of exposure for the remaining bonds
cannot be determined as these are largely bonds posted for the benefit of various municipalities relating to the normal course of business activities.

(e) $116-million exposure is related to $491 million of performance bonds associated with three construction projects in which Utility Engineering is participating.
An estimate of exposure for the remaining bonds cannot be determined as these are largely bonds posted for the benefit of various municipalities relating to the
normal course of business activities. Xcel Energy is not obligated under these agreements.

(f ) SPS would hold title to the collateral and would not be required to transfer the ownership of the additional transmission related facilities to the customer. SPS

would also have access to the customer sinking fund account, which is approximately $6.7 million.

page 80

xcel energy inc. and subsidiaries

notes to consolidated financial statements

Xcel Energy may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy
part or potentially all of these exposures, in the event that Standard & Poor’s or Moody’s downgrade Xcel Energy’s credit rating below
investment grade. In the event of a downgrade, Xcel Energy would expect to meet its collateral obligations with a combination of cash
on hand and, upon receipt of an SEC order permitting such actions, utilization of credit facilities and the issuance of securities in the
capital markets.

NRG is directly liable for the obligations of certain of its project affiliates and other subsidiaries pursuant to guarantees relating to
certain of their indebtedness, equity and operating obligations. In addition, in connection with the purchase and sale of fuel emission
credits and power generation products to and from third parties with respect to the operation of some of NRG’s generation facilities
in the United States, NRG may be required to guarantee a portion of the obligations of certain of its subsidiaries. As of Dec. 31, 2002,
NRG’s obligations pursuant to its guarantees of the performance, equity and indebtedness obligations of its subsidiaries totaled
approximately $374 million.

In addition, Xcel Energy provides indemnity protection for bonds issued for itself and its subsidiaries. The total amount of bonds with
this indemnity outstanding as of Dec. 31, 2002, was approximately $342.7 million, of which $6.4 million relates to NRG. The total
exposure of this indemnification cannot be determined at this time. Xcel Energy believes the exposure to be significantly less than the
total indemnification.

fair value of derivative instruments
The following discussion briefly describes the derivatives of Xcel Energy and its subsidiaries and discloses the respective fair values at
Dec. 31, 2002 and 2001. For more detailed information regarding derivative financial instruments and the related risks, see Note 17 to
the Consolidated Financial Statements.

Interest Rate Swaps On Dec. 31, 2002, NRG had interest rate swaps outstanding with a notional amount of approximately $1.7 billion.
The fair value of those swaps on Dec. 31, 2002, was a liability of approximately $41 million. Other subsidiaries of Xcel Energy also
had interest rate swaps outstanding with a notional amount of approximately $100 million, and a fair value that was a liability of
approximately $12 million, at Dec. 31, 2002.

As of Dec. 31, 2001, Xcel Energy had several interest rate swaps converting project financing from variable-rate debt to fixed-rate debt with
a notional amount of approximately $2.5 billion. The fair value of the swaps as of Dec. 31, 2001, was a liability of approximately $92 million.

Electric Trading Operations Xcel Energy participates in the trading of electricity as a commodity. This trading includes forward contracts,
futures and options. Xcel Energy makes purchases and sales at existing market points or combines purchases with available transmission
to make sales at other market points. Options and hedges are used to either minimize the risks associated with market prices, or to profit
from price volatility related to our purchase and sale commitments.

Beginning with the third quarter of 2002, Xcel Energy has presented the results of its electric trading activity using the net accounting
method. The Consolidated Statements of Operations for 2001 and 2000 have been reclassified to be consistent. In earlier presentations,
the gross accounting method was used. All financial derivative contracts and contracts that do not include physical delivery are recorded
at the amount of the gain or loss received from the contract. The mark-to-market adjustments for these transactions are appropriately
reported in the Consolidated Statements of Operations in Electric and Gas Trading Revenues.

Regulated Operations Xcel Energy’s regulated energy marketing operation uses a combination of electricity and natural gas purchase
for resale futures and forward contracts, along with physical supply, to hedge market risks in the energy market. At Dec. 31, 2002, the
notional value of these contracts was a liability of approximately $64.3 million. The fair value of these contracts as of Dec. 31, 2002,
was an asset of approximately $33.3 million.

Nonregulated Operations Xcel Energy’s nonregulated operations use a combination of energy futures and forward contracts, along with
physical supply, to hedge market risks in the energy market. At Dec. 31, 2002, the notional value of these contracts was approximately
$253.8 million. The fair value of these contracts as of Dec. 31, 2002, was an asset of approximately $69.3 million.

Foreign Currency Xcel Energy and its subsidiaries have two foreign currency swaps to hedge or protect foreign currency denominated cash
flows. At Dec. 31, 2002 and 2001, the net notional amount of these contracts was approximately $3 million and $46.3 million, respectively.
The fair value of these contracts as of Dec. 31, 2002 and 2001, was a liability of approximately $0.3 million and $2.4 million, respectively.

letters of credit
Xcel Energy and its subsidiaries use letters of credit, generally with terms of one or two years, to provide financial guarantees for certain
operating obligations. In addition, NRG uses letters of credit for nonregulated equity commitments, collateral for credit agreements, fuel
purchase and operating commitments, and bids on development projects. At Dec. 31, 2002, there were $154.6 million in letters of credit
outstanding, including $110.0 million related to NRG commitments. The contract amounts of these letters of credit approximate their
fair value and are subject to fees determined in the marketplace.

xcel energy inc. and subsidiaries          page 81

notes to consolidated financial statements

17. derivative valuation and financial impacts

use of derivatives to manage risk
Business and Operational Risk Xcel Energy and its subsidiaries are exposed to commodity price risk in their generation, retail distribution
and energy trading operations. In certain jurisdictions, purchased power 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, we recover purchased power expenses and natural gas costs based on fixed price limits or
under established sharing mechanisms.

Commodity price risk is managed by entering into purchase and sales commitments for electric power and natural gas, long-term contracts
for coal supplies and fuel oil, and derivative financial instruments. Xcel Energy’s risk management policy allows us 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 we use various physical contracts and derivative instruments to reduce the cost of natural
gas and electricity we provide to our retail customers even though the regulatory jurisdiction provides 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 are 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. Xcel Energy manages this market
price risk by entering into firm power sales agreements for approximately 55 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, we manage 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 us to
manage the market price risks and provides guidelines for the level of price risk exposure that is acceptable within our operations.

Xcel Energy is exposed to market price risk for the sale of electric energy and the purchase of fuel resources used to generate the
electric energy from our equity method investments that own electric operations. Xcel Energy manages this market price risk
through our involvement with the management committee or board of directors of each of these ventures. Our risk management
policy does not cover the activities conducted by the ventures. However, other policies are adopted by the ventures as necessary and
mandated by the equity owners.

Interest Rate Risk Xcel Energy and its subsidiaries are exposed to fluctuations in interest rates where we enter into variable rate debt
obligations to fund certain power projects being developed or purchased. Exposure to interest rate fluctuations may be mitigated by
entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure
to the volatility of cash flows for interest and result in primarily fixed-rate debt obligations when taking into account the combination of
the variable rate debt and the interest rate derivative instrument. Xcel Energy’s risk management policy allows us to reduce interest rate
exposure from variable rate debt obligations.

Currency Exchange Risk Xcel Energy and its subsidiaries have certain investments in foreign countries exposing us to foreign currency
exchange risk. The foreign currency exchange risk includes the risk relative to the recovery of our net investment in a project, as well as
the risk relative to the earnings and cash flows generated from such operations. Xcel Energy manages its exposure to changes in foreign
currency by entering into derivative instruments as determined by management. Our risk management policy provides for this risk
management activity.

Trading Risk Xcel Energy and its subsidiaries conduct various trading operations and power marketing activities, including the purchase
and sale of electric capacity and energy and natural gas. The trading operations are conducted both in the United States and Europe
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
our risk management committee made up of management personnel not involved in the trading operations.

derivatives as hedges
2001 Accounting Change On Jan. 1, 2001, Xcel Energy and its subsidiaries adopted SFAS No. 133 – “Accounting for Derivative
Instruments and Hedging Activities.” This statement requires that all derivative instruments as defined by SFAS No. 133 be recorded on the
balance sheet at fair value unless exempted. Changes in a derivative instrument’s fair value must be recognized currently in earnings unless
the derivative has been designated in a qualifying hedging relationship. The application of hedge accounting allows a derivative instrument’s
gains and losses to offset related results of the hedged item in the statement of operations, to the extent effective. SFAS No. 133 requires that
the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

A fair value hedge requires that the effective portion of the change in the fair value of a derivative instrument be offset against the change
in the fair value of the underlying asset, liability or firm commitment being hedged. That is, fair value hedge accounting allows the

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xcel energy inc. and subsidiaries

notes to consolidated financial statements

offsetting gain or loss on the hedged item to be reported in an earlier period to offset the gain or loss on the derivative instrument.
A cash flow hedge requires that the effective portion of the change in the fair value of a derivative instrument be recognized in
Other Comprehensive Income, and reclassified into earnings in the same period or periods during which the hedged transaction
affects earnings. The ineffective portion of a derivative instrument’s change in fair value is recognized currently in earnings.

Xcel Energy and its subsidiaries formally document hedge relationships, including, among other things, the identification of the hedging
instrument and the hedged transaction, as well as the risk management objectives and strategies for undertaking the hedged transaction.
Derivatives are recorded in the balance sheet at fair value. Xcel Energy and its subsidiaries also formally assess, both at inception and at
least quarterly thereafter, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value
or cash flows of the hedged items.

financial impacts of derivatives
The impact of the components of SFAS No. 133 on Xcel Energy’s Other Comprehensive Income, included in Stockholders’ Equity, are
detailed in the following table:

(Millions of dollars)

Net unrealized transition loss at adoption, Jan. 1, 2001
After-tax net unrealized gains related to derivatives accounted for as hedges
After-tax net realized losses on derivative transactions reclassified into earnings
Accumulated other comprehensive income related to SFAS No. 133 at Dec. 31, 2001
After-tax net unrealized losses related to derivatives accounted for as hedges
After-tax net realized losses on derivative transactions reclassified into earnings
Acquisition of NRG minority interest
Accumulated other comprehensive income related to SFAS No. 133 at Dec. 31, 2002

$(28.8)
43.6
19.4
$34.2
(68.3)
28.8
27.4
$22.1

Xcel Energy records the fair value of its derivative instruments in its Consolidated Balance Sheet as a separate line item noted as
“Derivative Instruments Valuation” for assets and liabilities, as well as current and noncurrent.

Cash Flow Hedges Xcel Energy and its subsidiaries enter into derivative instruments to manage exposure to changes in commodity prices.
These derivative instruments take the form of fixed-price, floating-price or index sales, or purchases and options, such as puts, calls and
swaps. These derivative instruments are designated as cash flow hedges for accounting purposes, and the changes in the fair value of these
instruments are recorded as a component of Other Comprehensive Income. At Dec. 31, 2002, Xcel Energy had various commodity-
related contracts extending through 2018. Amounts deferred in Other Comprehensive Income are recorded as the hedged purchase or
sales transaction is completed. This could include the physical sale of electric energy or the use of natural gas to generate electric energy.
Xcel Energy expects to reclassify into earnings during 2003 net gains from Other Comprehensive Income of approximately $12.9 million.

Xcel Energy and its subsidiaries enter into interest rate swap instruments that effectively fix the interest payments on certain floating
rate debt obligations. These derivative instruments are designated as cash flow hedges for accounting purposes, and the change in the
fair value of these instruments is recorded as a component of Other Comprehensive Income. Xcel Energy expects to reclassify into
earnings during 2003 net losses from Other Comprehensive Income of approximately $13.4 million.

Hedge effectiveness is recorded based on the nature of the item being hedged. Hedging transactions for the sales of electric energy are
recorded as a component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs,
and hedging transactions for interest rate swaps are recorded as a component of interest expense.

Hedges of Foreign Currency Exposure of a Net Investment in Foreign Operations To preserve the U.S. dollar value of projected foreign
currency cash flows, Xcel Energy, through NRG, may hedge, or protect, those cash flows if appropriate foreign hedging instru-
ments are available.

Derivatives Not Qualifying for Hedge Accounting Xcel Energy and its subsidiaries have trading operations that enter into derivative
instruments. These derivative instruments are accounted for on a mark-to-market basis in the Consolidated Statements of Operations.
All derivative instruments are recorded at the amount of the gain or loss from the transaction within Operating Revenues on the
Consolidated Statements of Operations.

Normal Purchases or Normal Sales Xcel Energy and its subsidiaries enter into fixed-price contracts for the purchase and sale of various
commodities for use in its business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the
contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133 as
normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something
other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable
period in the normal course of business. Contracts that meet the requirements of normal are documented as normal and exempted from
the accounting and reporting requirements of SFAS No. 133.

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notes to consolidated financial statements

Xcel Energy evaluates all of its contracts within the regulated and nonregulated operations when such contracts are entered to determine
if they are derivatives and if so, if they qualify and meet the normal designation requirements under SFAS No. 133. None of the contracts
entered into within the trading operation are considered normal.

Normal purchases and normal sales contracts are accounted for as executory contracts as required under other generally accepted
accounting principles.

18. commitments and contingencies

commitments
Legislative Resource Commitments In 1994, NSP-Minnesota received Minnesota legislative approval for additional on-site temporary
spent fuel storage facilities at its Prairie Island nuclear power plant, provided NSP-Minnesota satisfies certain requirements. Seventeen
dry cask containers were approved. As of Dec. 31, 2002, NSP-Minnesota had loaded 17 of the containers. The Minnesota Legislature
established several energy resource and other commitments for NSP-Minnesota to obtain the Prairie Island temporary nuclear fuel storage
facility approval. These commitments can be met by building, purchasing or, in the case of biomass, converting generation resources.

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

See additional discussion of the current operating contingency related to the spent fuel storage facilities under Operating Contingency.

Capital Commitments As discussed in Liquidity and Capital Resources under Management’s Discussion and Analysis, the estimated
cost, as of Dec. 31, 2002, of the capital expenditure programs of Xcel Energy and its subsidiaries and other capital requirements is
approximately $1.5 billion in 2003, $1.2 billion in 2004 and $1.3 billion in 2005.

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 merger, acquisition and divestiture opportunities to support corporate strategies, address restructuring
requirements and comply with future requirements to install emission-control equipment may impact actual capital requirements.

Support and Capital Subscription Agreement In May 2002, Xcel Energy and NRG entered into a support and capital subscription
agreement pursuant to which Xcel Energy agreed under certain circumstances to provide up to $300 million to NRG. Xcel Energy
has not to date provided funds to NRG under this agreement. However, Xcel Energy is willing to make a contribution of $300 million
if the restructuring plan discussed earlier is approved by the creditors. See additional discussion of NRG restructuring at Note 4.

Leases Our subsidiaries lease a variety of equipment and facilities used in the normal course of business. Some of these leases qualify as
capital leases and are accounted for accordingly. The capital leases expire between 2002 and 2025. The net book value of property under
capital leases was approximately $624 million and $605 million at Dec. 31, 2002 and 2001, respectively. Assets acquired under capital
leases are recorded as property at the lower of fair-market value or the present value of future lease payments and are amortized over their
actual contract term in accordance with practices allowed by regulators. The related obligation is classified as long-term debt. Executory
costs are excluded from the minimum lease payments.

The remainder of the leases, primarily real estate leases and leases of coal-hauling railcars, trucks, cars and power-operated equipment,
are accounted for as operating leases. Rental expense under operating lease obligations was approximately $86 million, $58 million and
$56 million for 2002, 2001 and 2000, respectively.

Future commitments under operating and capital leases are:

(Millions of dollars)

2003
2004
2005
2006
2007
Thereafter

Total minimum obligation

Interest

Present value of minimum obligation

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xcel energy inc. and subsidiaries

Operating
Leases

$ 66
64
61
58
51
86

Capital
Leases

$

83
80
78
75
73
1,030
$1,419
(795)
$ 624

notes to consolidated financial statements

Technology Agreement We have a contract that extends through 2011 with International Business Machines Corp. (IBM) for information
technology services. The contract is cancelable at our option, although there are financial penalties for early termination. In 2002, we paid
IBM $131.9 million under the contract and $26 million for other project business. The contract also commits us to pay a minimum
amount each year from 2002 through 2011.

Fuel Contracts Xcel Energy has contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel
and natural gas requirements. These contracts expire in various years between 2003 and 2025. In total, Xcel Energy is committed to the
minimum purchase of approximately $2.3 billion of coal, $122.2 million of nuclear fuel and $1.6 billion of natural gas, including $1.2 billion
of natural gas storage and transportation, or to make payments in lieu thereof, under these contracts. In addition, Xcel Energy is required
to pay additional amounts depending on actual quantities shipped under these agreements. Xcel Energy’s risk of loss, in the form of
increased costs, from market price changes in fuel is mitigated through the cost-of-energy adjustment provision of the ratemaking
process, which provides for recovery of most fuel costs.

Purchased Power Agreements The utility and nonregulated subsidiaries of Xcel Energy have entered into agreements with utilities and
other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units
under maintenance and during outages, and meet operating reserve obligations. NSP-Minnesota, PSCo, SPS and certain nonregulated
subsidiaries have various pay-for-performance contracts with expiration dates through the year 2050. In general, these contracts provide
for capacity payments, subject to meeting certain contract obligations, and energy payments based on actual power taken under the
contracts. Most of the capacity and energy costs are recovered through base rates and other cost-recovery mechanisms.

NSP-Minnesota has a 500-megawatt participation power purchase commitment with Manitoba Hydro, which expires in 2005. The
cost of this agreement is based on 80 percent of the costs of owning and operating NSP-Minnesota’s Sherco 3 generating plant,
adjusted to 1993 dollars. This agreement was extended through a new agreement during 2002 to include the period starting May 2005
through April 2015. The cost of the agreement for this extended period is based on a base price, which was established from May 2001
through April 2002 and will be escalated by the change in the United States gross national product to reflect the current year. In
addition, NSP-Minnesota and Manitoba Hydro have seasonal diversity exchange agreements, and there are no capacity payments for the
diversity exchanges. These commitments represent about 17 percent of Manitoba Hydro’s system capacity and account for approximately
9 percent of NSP-Minnesota’s 2002 electric system capability. The risk of loss from nonperformance by Manitoba Hydro is not considered
significant, and the risk of loss from market price changes is mitigated through cost-of-energy rate adjustments.

At Dec. 31, 2002, the estimated future payments for capacity that the utility and nonregulated subsidiaries of Xcel Energy are obligated
to purchase, subject to availability, are as follows:

(Thousands of dollars)

2003
2004
2005
2006
2007 and thereafter

Total

Total

$ 528,978
548,173
549,261
540,245
5,067,551
$7,234,208

environmental contingencies
We are subject to regulations covering air and water quality, land use, the storage of natural gas and the storage and disposal of hazardous
or toxic wastes. We continuously assess our compliance. Regulations, interpretations and enforcement policies can change, which may
impact the cost of building and operating our facilities. This includes NRG, which is subject to regional, federal and international
environmental regulation.

Site Remediation We must pay all or a portion of the cost to remediate sites where past activities of our subsidiaries and some other
parties have caused environmental contamination. At Dec. 31, 2002, there were three categories of sites:

– third-party sites, such as landfills, to which we are alleged to be a potentially responsible party (PRP) that sent hazardous materials

and wastes;

– the site of a former federal uranium enrichment facility; and
– sites of former manufactured gas plants (MGPs) operated by our subsidiaries or predecessors.

We record a liability when we have enough information to develop an estimate of the cost of environmental remediation and revise the
estimate as information is received. The estimated remediation cost may vary materially.

To estimate the cost to remediate these sites, we may have to make assumptions when facts are not fully known. For instance, we might
make assumptions about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup
methods and pollution-control technologies, the period over which remediation will be performed and paid for, changes in environmental
remediation and pollution-control requirements, the potential effect of technological improvements, the number and financial strength
of other PRPs and the identification of new environmental cleanup sites.

xcel energy inc. and subsidiaries          page 85

notes to consolidated financial statements

We revise our estimates as facts become known but, at Dec. 31, 2002, our liability for the cost of remediating sites, including NRG,
for which an estimate was possible was $49 million, of which $11 million was considered to be a current liability. Some of the cost of
remediation may be recovered from:

– insurance coverage;
– other parties that have contributed to the contamination; and
– customers.

Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined.
We have recorded estimates of our share of future costs for these sites. We are not aware of any other parties’ inability to pay, nor do we
know if responsibility for any of the sites is in dispute.

Approximately $15 million of the long-term liability and $4 million of the current liability relate to a U.S. Department of Energy
assessment to NSP-Minnesota and PSCo for decommissioning a federal uranium enrichment facility. These environmental liabilities
do not include accruals recorded and collected from customers in rates for future nuclear fuel disposal costs or decommissioning costs
related to NSP-Minnesota’s nuclear generating plants. See Note 19 to the Consolidated Financial Statements for further discussion of
nuclear obligations.

Ashland MGP Site NSP-Wisconsin was named as one of three PRPs for creosote and coal tar contamination at a site in Ashland, Wis.
The Ashland site includes property owned by NSP-Wisconsin and two other properties: an adjacent city lakeshore park area and a small
area of Lake Superior’s Chequemegon Bay adjoining the park.

The Wisconsin Department of Natural Resources (WDNR) and NSP-Wisconsin have each developed several estimates of the ultimate
cost to remediate the Ashland site. The estimates vary significantly, between $4 million and $93 million, because different methods of
remediation and different results are assumed in each. The Environmental Protection Agency (EPA) and WDNR have not yet selected
the method of remediation to use at the site. Until the EPA and the WDNR select a remediation strategy for all operable units at the
site and determine the level of responsibility of each PRP, we are not able to accurately determine our share of the ultimate cost of
remediating the Ashland site.

In the interim, NSP-Wisconsin has recorded a liability of $19 million for its estimate of its share of the cost of remediating the portion
of the Ashland site that it owns, using information available to date and reasonably effective remedial methods. NSP-Wisconsin has
deferred, as a regulatory asset, the remediation costs accrued for the Ashland site because we expect that the Public Service Commission
of Wisconsin (PSCW) will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers.
The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site, and has
authorized recovery of similar remediation costs for other Wisconsin utilities.

As an interim action, Xcel Energy proposed, and the EPA and WDNR have approved, a coal tar removal/groundwater treatment system
for one operable unit at the site for which NSP-Wisconsin has accepted responsibility. The groundwater treatment system began operating
in the fall of 2000. In 2002, NSP-Wisconsin installed additional monitoring wells in the deep aquifer to better characterize the extent
and degree of contaminants in that aquifer while the coal tar removal system is operational. In 2002, a second interim response action
was also implemented. As approved by the WDNR, this interim response action involved the removal and capping of a seep area in a
city park. Surface soils in the area of the seep were contaminated with tar residues. The interim action also included the diversion and
ongoing treatment of groundwater that contributed to the formation of the seep.

On Sept. 5, 2002, the Ashland site was placed on the National Priorities List (NPL). The NPL is intended primarily to guide the EPA
in determining which sites require further investigation. Resolution of Ashland remediation issues is not expected until 2004 or 2005.

NSP-Wisconsin continues to work with the WDNR to access state and federal funds to apply to the ultimate remediation cost of the
entire site.

Other MGP Sites NSP-Minnesota has investigated and remediated MGP sites in Minnesota and North Dakota. The MPUC allowed
NSP-Minnesota to defer, rather than immediately expense, certain remediation costs of four active remediation sites in 1994. This deferral
accounting treatment may be used to accumulate costs that regulators might allow us to recover from our customers. The costs are
deferred as a regulatory asset until recovery is approved, and then the regulatory asset is expensed over the same period as the regulators
have allowed us to collect the related revenue from our customers. In September 1998, the MPUC allowed the recovery of a portion of
these MGP site remediation costs in natural gas rates. Accordingly, NSP-Minnesota has been amortizing the related deferred remediation
costs to expense. In 2001, the North Dakota Public Service Commission allowed the recovery of part of the cost of remediating another
former MGP site in Grand Forks, N.D. The $2.9-million recovered cost of remediating that site was accumulated in a regulatory asset
that is now being expensed evenly over eight years. NSP-Minnesota may request recovery of costs to remediate other sites following the
completion of preliminary investigations.

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notes to consolidated financial statements

NRG Site Remediation As part of acquiring existing generating assets, NRG has acquired certain environmental liabilities associated
with regulatory compliance and site contamination. Often, potential compliance implementation plans are changed, delayed or abandoned
due to one or more of the following conditions: (a) extended negotiations with regulatory agencies, (b) a delay in promulgating rules
critical to dictating the design of expensive control systems, (c) changes in governmental/regulatory personnel, (d) changes in governmental
priorities or (e) selection of a less expensive compliance option than originally envisioned.

In response to liabilities associated with these activities, NRG has established accruals where reasonable estimates of probable liabilities
are possible. As of Dec. 31, 2002 and 2001, NRG has established such accruals in the amount of approximately $3.8 million and
$5.0 million, respectively, primarily related to its Northeast region facilities. NRG has not used discounting in determining its accrued
liabilities for environmental remediation and no claims for possible recovery from third party issuers or other parties related to environmental
costs have been recognized in NRG’s consolidated financial statements. NRG adjusts the accruals when new remediation responsibilities
are discovered and probable costs become estimable, or when current remediation estimates are adjusted to reflect new information.
During the years ended Dec. 31, 2002, 2001 and 2000, NRG recorded expenses of approximately $10.9 million, $15.3 million and
$3.4 million related to environmental matters, respectively.

Asbestos Removal Some of our facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are
demolished or renovated. Since we intend to operate most of these facilities indefinitely, we cannot estimate the amount or timing of
payments for its final removal. It may be necessary to remove some asbestos to perform maintenance or make improvements to other
equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for
maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Leyden Gas Storage Facility In February 2001, the CPUC granted PSCo’s application to abandon the Leyden natural gas storage facility
(Leyden) after 40 years of operation. In July 2001, the CPUC decided that the recovery of all Leyden costs would be addressed in a
future rate proceeding when all costs were known. Since late 2001, PSCo has operated the facility to withdraw the recoverable gas in
inventory. Beginning in 2003, PSCo will start to flood the facility with water, as part of an overall plan to convert Leyden into a municipal
water storage facility owned and operated by the city of Arvada, Colo. As of Dec. 31, 2002, PSCo has deferred approximately $4.5 million
of costs associated with engineering buffer studies, damage claims paid to landowners and other closure costs. PSCo expects to incur an
additional $6 million to $8 million of costs through 2005 to complete the decommissioning and closure of the facility. PSCo believes
that these costs will be recovered through future rates. Any costs that are not recoverable from customers will be expensed.

PSCo Notice of Violation On Nov. 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for
alleged violations of the Clean Air Act’s New Source Review (NSR) requirements related to alleged modifications of electric generating
stations located in the South and Midwest. Subsequently, the U. S. Environmental Protection Agency (EPA) also issued requests for
information pursuant to the Clean Air Act to numerous other electric utilities, including Xcel Energy, seeking to determine whether
these utilities engaged in activities that may have been in violation of the NSR requirements. In 2001, Xcel Energy responded to EPA’s
initial information requests related to PSCo plants in Colorado.

On July 1, 2002, Xcel Energy received a Notice of Violation (NOV) from the EPA alleging violations of the NSR requirements of the
Clean Air Act at the Comanche and Pawnee stations in Colorado. The NOV specifically alleges that various maintenance, repair and
replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. Xcel
Energy believes it acted in full compliance with the Clean Air Act and NSR process. It believes that the projects identified in the NOV
fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject
to the NSR requirements. Xcel Energy also believes that the projects would be expressly authorized under the EPA’s NSR policy
announced by the EPA administrator on June 22, 2002, and proposed in the Federal Register on Dec. 31, 2002. Xcel Energy disagrees
with the assertions contained in the NOV and intends to vigorously defend its position. As required by the Clean Air Act, the EPA
met with Xcel Energy in September 2002 to discuss the NOV.

If the EPA is successful in any subsequent litigation regarding the issues set forth in the NOV or any matter arising as a result of its
information requests, it could require Xcel Energy to install additional emission-control equipment at the facilities and pay civil penalties.
Civil penalties are limited to not more than $25,000 to $27,500 per day for each violation, commencing from the date the violation
began. The ultimate financial impact to Xcel Energy is not determinable at this time.

NSP-Minnesota NSR Information Request As stated previously, on Nov. 3, 1999, the United States Department of Justice filed suit
against a number of electric utilities for alleged violations of the Clean Air Act’s NSR requirements related to alleged modifications of
electric generating stations located in the South and Midwest. Subsequently, the EPA also issued requests for information pursuant to
the Clean Air Act to numerous other electric utilities, including Xcel Energy, seeking to determine whether these utilities engaged in
activities that may have been in violation of the NSR requirements. In 2001, Xcel Energy responded to the EPA’s initial information
requests related to NSP-Minnesota plants in Minnesota. On May 22, 2002, the EPA issued a follow-up information request to Xcel
Energy seeking additional information regarding NSR compliance at its plants in Minnesota. Xcel Energy completed its response to
the follow-up information request during the fall of 2002.

xcel energy inc. and subsidiaries          page 87

notes to consolidated financial statements

NSP-Minnesota Notice of Violation On Dec. 10, 2001, the Minnesota Pollution Control Agency issued a notice of violation to NSP-
Minnesota alleging air quality violations related to the replacement of a coal conveyor and violations of an opacity limitation at the A.S.
King generating plant. NSP-Minnesota has responded to the notice of violation and is working to resolve the allegations.

Nuclear Insurance NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $9.4 billion under the 1988
Price-Anderson amendment to the Atomic Energy Act of 1954. NSP-Minnesota has secured $200 million of coverage for its public
liability exposure with a pool of insurance companies. The remaining $9.2 billion of exposure is funded by the Secondary Financial
Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to
assessments of up to $88 million for each of its three licensed reactors to be applied for public liability arising from a nuclear incident at
any licensed nuclear facility in the United States. The maximum funding requirement is $10 million per reactor during any one year.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd.
(NEIL). The coverage limits are $1.5 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption
insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating
units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if
losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota
would have no exposure for retroactive premium assessments in the case of a single incident under the business interruption and the
property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of
approximately $7.5 million for business interruption insurance and $21.6 million for property damage insurance if losses exceed
accumulated reserve funds.

Louisiana Generating – Pointe Coupee On Dec. 2, 2002, a petition was filed to appeal the EPA’s approval of the Louisiana Department
of Environmental Quality’s (LDEQ) revisions to the state implementation plan (SIP) regarding emissions regulations. Pointe Coupee
and NRG’s subsidiary, Louisiana Generating, object to the permitting requirements regarding nitrogen oxide (NOx) sources requiring the
LDEQ to obtain offsets of major increases in emissions of NOx associated with major modifications of existing facilities or construction of
new facilities areas, including Pointe Coupee Parish. The plaintiffs’ challenge is based on LDEQ’s failure to comply with requirements
related to rulemaking and the EPA’s regulations, which prohibit EPA from approving a SIP not prepared in accordance with state law. The
court granted a 60-day stay of this proceeding on Feb. 25, 2003, to allow the parties to conduct settlement discussions. At this time, NRG
is unable to predict the eventual outcome of this matter or any potential loss contingencies.

Louisiana Generating – New Construction Air Permits During 2000, the LDEQ issued an air permit modification to Louisiana Generating
to construct and operate two 240-megawatt, natural gas-fired turbines. The permit set emissions limits for certain air pollutants, including
NOx. The limitation for NOx was based on the guarantees of the manufacturer, Siemens Westinghouse Power Corporation (Siemens).
Louisiana Generating sought an interim emissions limit to allow Siemens time to install additional control equipment. To establish the
interim limit, LDEQ issued an order and Notice of Potential Penalty in September 2002, which is, in part, subject to a hearing. LDEQ
alleged that Louisiana Generating did not meet its NOx emissions limit on certain days, did not conduct all opacity monitoring and did
not complete all record keeping and certification requirements. Louisiana Generating intends to vigorously defend certain claims and any
future penalty assessment, while also seeking an amendment of its limit for NOx. An initial status conference has been held with the
administrative law judge, and quarterly reports will be submitted to describe progress, including settlement and amendment of the limit.
In addition, NRG may assert breach of warranty claims against the manufacturer. With respect to the administrative action described
above, at this time NRG is unable to predict the eventual outcome of this matter or the potential loss contingencies, if any, to which
NRG may be subject.

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

The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have
a material adverse effect on Xcel Energy’s financial position and results of operations.

St. Cloud Gas Explosion On Dec. 11, 1998, a natural gas explosion in St. Cloud, Minn., killed four people, including two NSP-Minnesota
employees, injured approximately 14 people and damaged several buildings. The accident occurred as a crew from Cable Constructors
Inc. (CCI) was installing fiber-optic cable for Seren. Seren, CCI and Sirti, an architecture/engineering firm retained by Seren, are named
as defendants in 24 lawsuits relating to the explosion. NSP-Minnesota, Seren’s parent company at the time, is a defendant in 21 of the
lawsuits. In addition to compensatory damages, plaintiffs are seeking punitive damages against CCI and Seren. NSP-Minnesota and
Seren deny any liability for this accident. On July 11, 2000, the National Transportation Safety Board issued a report, which determined
that CCI’s inadequate installation procedures and delay in reporting the natural gas hit were the proximate causes of the accident.
NSP-Minnesota has a self-insured retention deductible of $2 million with general liability coverage limits of $185 million. Seren’s
primary insurance coverage is $1 million and its secondary insurance coverage is $185 million. The ultimate cost to Xcel Energy,
NSP-Minnesota and Seren, if any, is presently unknown.

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California Litigation NRG and other power generators and power traders have been named as defendants in a multi-district litigation
proceeding. These cases were all filed in late 2000 and 2001 in various state courts throughout California. They allege unfair competition,
market manipulation and price fixing. All the cases were removed to the appropriate United States District Courts, and were thereafter
made the subject of a petition to the multi-district litigation panel. The cases were ultimately assigned to Judge Whaley. In December
2002, Judge Whaley issued an opinion finding that federal jurisdiction was absent in the district court, and remanded the cases to state
court. On Feb. 20, 2003, however, the Ninth Circuit stayed the remand order and accepted jurisdiction to hear an appeal of the remand
order. NRG anticipates that filed-rate/federal preemption pleading challenges will once again be filed once the remand appeal is decided.
A notice of bankruptcy filing regarding NRG has also been filed in this action, providing notice of the involuntary petition.

Although the complaints contain a number of allegations, the basic claim is that by underbidding forward contracts and exporting
electricity to surrounding markets, the defendants, acting in collusion, were able to drive up wholesale prices on the Real Time and
Replacement Reserve markets, through the Western Coordinating Council and otherwise. The complaints allege that the conduct violated
California antitrust and unfair competition laws. NRG does not believe that it has engaged in any illegal activities, and intends to vigorously
defend these lawsuits. These six civil actions brought against NRG and other power generators and power traders in California have
been consolidated in the San Diego County Superior Court, and the plaintiffs in these six consolidated civil actions filed a master
amended complaint reiterating the allegations contained in their complaints and alleging that the defendants’ anti-competitive conduct
damaged the general public and class members in an amount in excess of $1.0 billion. Two of the defendants in these actions, Reliant
and Duke, subsequently filed cross-complaints naming additional market participants, some of whom removed the actions to the United
States District Court for the Southern District of California federal court. Now under advisement in that court is the plaintiffs’ motion
to remand the cases to state court and motions by the cross-defendants to dismiss the cases against them.

In addition, Public Utility District No. 1 of Snohomish County, Washington, has filed a suit against NRG, Xcel Energy and several
other market participants in United States District Court for the Central District of California contending that some of its trading
strategies, as reported to the FERC in response to that agency’s investigation of trading strategies discussed above, violated the California
Business and Professions Code. Public Utility District No. 1 of Snohomish County contends that the effect of those strategies was
to increase amounts that it paid for wholesale power in the spot market in the Pacific Northwest. Judge Whaley granted a motion
to dismiss on the grounds of federal preemption and filed-rate doctrine, which the plaintiffs have appealed.

Separate class action lawsuits alleging unfair competition similar to those filed in California, as discussed previously, have been filed in
Oregon and Washington. These lawsuits have named both Xcel Energy and NRG as respondents.

California Attorney General
In addition to the litigation described above, the California Attorney General has undertaken an investigation
into actions affecting electricity prices in California. In connection with this investigation, the Attorney General has issued subpoenas
and requested other information from Dynegy and NRG. NRG responded to the interrogatories as requested. Management cannot
make any evaluation of the likelihood of an unfavorable outcome or an estimate of the amount or range of potential loss in the above-
referenced private actions at this time. NRG knows of no evidence implicating NRG in plaintiffs’ allegations of collusion.

FirstEnergy Arbitration Claim In August 2002, FirstEnergy terminated the purchase agreements pursuant to which NRG had agreed
to purchase four generating stations for approximately $1.5 billion. FirstEnergy’s cited rationale for terminating the agreements was an
alleged anticipatory breach by NRG. FirstEnergy notified NRG that it is reserving the right to pursue legal action against NRG and
Xcel Energy for damages. On Feb. 21, 2003, FirstEnergy submitted filings with the United States Bankruptcy Court in Minnesota
seeking permission to file a demand for arbitration against NRG. On Feb. 26, 2002, FirstEnergy commenced the arbitration proceedings
against NRG, but have yet to quantify their damage claim. NRG cannot presently predict the outcome of this dispute.

General Electric Company and Siemens Westinghouse Turbine Purchase Disputes NRG and/or its affiliates have entered into several turbine
purchase agreements with affiliates of General Electric Company (GE) and Siemens. GE and Siemens have notified NRG that it is in
default under certain of those contracts, terminated such contracts and demanded that NRG pay the termination fees set forth in such
contracts. GE’s claim amounts to $120 million and Siemens’ approximately $45 million in cumulative termination charges. NRG has
recorded a liability for the amounts they believe they owe under the contracts and termination provisions. NRG cannot estimate the
likelihood of unfavorable outcomes in these disputes.

Fortistar Litigation On Feb. 26, 2003, Fortistar Capital, Inc. and Fortistar Methane, LLC filed a $1-billion lawsuit in the Federal District
Court for the Northern District of New York against Xcel Energy Inc. and five former NRG or NEO Corp. employees. In the lawsuit,
Fortistar claims that the defendants violated the Racketeer Influenced and Corrupt Organizations Act (RICO) and committed fraud by
engaging in a pattern of negotiating and executing agreements “they intended not to comply with” and “made false statements later to
conceal their fraudulent promises.” The allegations against Xcel Energy are, for the most part, limited to purported activities related to the
contract for the Pike Energy power facility in Mississippi and statements related to an “equity infusion” into NRG by Xcel Energy. The
plaintiffs allege damages of some $350 million and also assert entitlement to a trebling of these damages under the provisions of the
RICO. The present and former NRG and NEO officers and employees have requested indemnity from NRG, which requests NRG is
now examining. Xcel Energy cannot at this time estimate the likelihood of an unfavorable outcome to the defendants in this lawsuit.

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Itiquira Energetica NRG’s indirectly controlled Brazilian project company, Itiquira Energetica S.A., the owner of a 156-megawatt hydro
project in Brazil, is currently in arbitration with a former contractor for the project Inepar Industria e Construcoes (Inepar). The dispute
was commenced by Itiquira in September 2002 and pertains to certain matters arising under the agreement with the contractor. Itiquira
principally asserts that Inepar breached the contract and caused damages to Itiquira by (i) failing to meet milestones for substantial
completion; (ii) failing to provide adequate resources to meet such milestones; (iii) failing to pay subcontractors amounts due; and (iv)
being insolvent. Itiquira’s arbitration claim is for approximately $40 million. Inepar has asserted in the arbitration that Itiquira breached
the contact and caused damages to Inepar by failing to recognize events of force majeure as grounds for excused delay and extensions of
scope of services and material under the contract. Inepar’s damage claim is for approximately $10 million. On Nov. 12, 2002, Inepar
submitted its affirmative statement of claim, and Itiquira submitted its response and statement of counterclaims on Dec. 14, 2002.
Inepar replied to Itiquira’s response and counterclaims on Jan. 14, 2003. Itiquira was to submit its reply on March 14, 2003, and a hearing
was held on March 21, 2003. NRG cannot estimate the likelihood of an unfavorable outcome in this dispute.

NRG Bankruptcy On Oct. 17, 2002, a petition commencing an involuntary bankruptcy proceeding pursuant to Chapter 7 of the
Bankruptcy Code was filed against LSP-Pike Energy, LLC, a subsidiary of NRG, by Stone & Webster, Inc. and Shaw Constructors,
Inc., the joining petitioners in the Minnesota involuntary case described previously, in the United States Bankruptcy Court for the
Southern District of Mississippi. In their petition, the joining petitioners sought recovery of allegedly unpaid contractual construction-
related obligations in an aggregate amount of $74 million, which amount LSP-Pike Energy, LLC has disputed. LSP-Pike Energy, LLC
filed an answer to the petition in the Mississippi involuntary case and served various interrogatory and deposition discovery requests on
the joining petitioners. The Mississippi Bankruptcy Court has not entered any order for relief in the Mississippi involuntary case.

On Nov. 22, 2002, five former NRG executives filed an involuntary Chapter 11 petition against NRG in the United States Bankruptcy
Court for the District of Minnesota (Minnesota Bankruptcy Court). Under provisions of federal law, NRG has the full authority to
continue to operate its business as if the involuntary petition had not been filed unless and until a court hearing on the validity of the
involuntary petition is resolved adversely to NRG. NRG responded to the involuntary petition, contesting the petitioners’ claims and
filing a motion to dismiss the case. A hearing was set for April 10, 2003, to consider the motion to dismiss. In their petition, the
petitioners sought recovery of severance and other benefits of approximately $28 million.

NRG and its counsel have been involved in negotiations with the petitioners and their counsel. As a result of these negotiations, NRG
and the petitioners reached an agreement and compromise regarding their respective claims against each other (Settlement Agreement).
In February 2003, the Settlement Agreement was executed, pursuant to which NRG agreed to pay the petitioners an aggregate settlement
in the amount of $12 million.

On Feb. 28, 2003, Stone & Webster, Inc. and Shaw Constructors, Inc. filed a petition alleging that they hold unsecured, non-contingent
claims against NRG in a joint amount of $100 million. The Minnesota Bankruptcy Court has discretion in reviewing and ruling on the
motion to dismiss and the review and approval of the Settlement Agreement. There is a risk that the Minnesota Bankruptcy Court may,
among other things, reject the Settlement Agreement or enter an order for relief under Chapter 11 of Title 11 of the Bankruptcy Code.

See Note 4 for additional discussion of possible NRG bankruptcy.

NRG Energy, Inc. Shareholder Litigation (Delaware); Rosenfeld v. NRG Energy, Inc. (Minnesota) In February 2002, individual stockholders
of NRG filed nine separate, but similar, purported class action complaints in the Delaware Court of Chancery, subsequently consolidated
and with a single amended complaint, against Xcel Energy, NRG and the nine members of NRG’s board of directors. In March 2002,
a similar class action lawsuit was filed in the state trial court for Hennepin County, Minnesota. Each of the actions challenged the proposed
purchase by Xcel Energy, via exchange offer and follow-up merger, of the approximately 26 percent of the outstanding shares of NRG that
it did not already own; contained various allegations of wrongdoing on the part of the defendants in connection with the proposed purchase,
including violations of fiduciary duties of loyalty and candor; and sought injunctive and damage relief and an award of fees and expenses. In
April 2002, counsel for the parties to the consolidated action in the Delaware Court of Chancery and the Minnesota action entered into a
memorandum of understanding setting forth an agreement in principle to settle the actions based on the increase by Xcel Energy of the
exchange ratio in the offer and merger to 0.5000 but subject to confirmatory discovery, definitive documentation and court approval. The
Minnesota action has subsequently been dismissed without prejudice. As to the Delaware actions, the settlement has not been documented,
approved or consummated, and, in light of developments in the litigation that is described under the heading immediately below, it is
uncertain whether the settlement will proceed.

Xcel Energy Inc. Securities Litigation On July 31, 2002, a lawsuit purporting to be a class action on behalf of purchasers of Xcel Energy’s
common stock between Jan. 31, 2001, and July 26, 2002, was filed in the United States District Court for the District of Minnesota.
The complaint named Xcel Energy; Wayne H. Brunetti, chairman, president and chief executive officer; Edward J. McIntyre, former
vice president and chief financial officer; and former chairman James J. Howard as defendants. Among other things, the complaint alleged
violations of Section 10(b) of the Securities Exchange Act and Rule 10(b-5) related to allegedly false and misleading disclosures concerning
various issues, including but not limited to “round trip” energy trades, the nature, extent and seriousness of liquidity and credit difficulties
at NRG, and the existence of cross-default provisions (with NRG credit agreements) in certain of Xcel Energy’s credit agreements.

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After the filing of the lawsuit, several additional lawsuits were filed with similar allegations, one of which added claims on behalf of a
purported class of purchasers of two series of Senior Notes issued by NRG in January 2001. The cases have all been consolidated, and
a consolidated amended complaint has been filed. The amended complaint charges false and misleading disclosures concerning “round
trip” energy trades and the existence of provisions in Xcel Energy’s credit agreements for cross-defaults in the event of a default by NRG in
one or more of NRG’s credit agreements; it adds as additional defendants Gary R. Johnson, general counsel; Richard C. Kelly, president
of Xcel Energy Enterprises; three former executive officers of NRG, David H. Peterson, Leonard A. Bluhm and William T. Pieper, and a
former independent director of NRG, Luella G. Goldberg; and it adds claims of false and misleading disclosures, also regarding “round
trip” trades and the cross-default provisions, as well the extent to which the “fortunes” of NRG were tied to Xcel Energy, especially
in the event of a buyback of NRG’s publicly owned shares, under Section 11 of the Securities Act with respect to issuance of the
Senior Notes. The amended complaint seeks compensatory and rescissionary damages, interest and an award of fees and expenses. The
defendants have not yet responded to the amended complaint. Discovery has not commenced.

Xcel Energy Inc. Shareholder Derivative Action; Essmacher v. Brunetti; McLain v. Brunetti On Aug. 15, 2002, a shareholder derivative action
was filed in the United States District Court for the District of Minnesota, purportedly on behalf of Xcel Energy, against the directors and
certain present and former officers, citing essentially the same circumstances as the securities class actions described immediately preceding
and asserting breach of fiduciary duty. This action has been consolidated for pre-trial purposes with the securities class actions. After the
filing of this action, two additional derivative actions were filed in the state trial court for Hennepin County, Minnesota, against essentially
the same defendants, focusing on allegedly wrongful energy trading activities and asserting breach of fiduciary duty for failure to establish
adequate accounting controls, abuse of control and gross mismanagement. Considered collectively, the complaints seek compensatory
damages, a return of compensation received and awards of fees and expenses. In each of the cases, the defendants have filed motions to
dismiss the complaint for failure to make a proper pre-suit demand, or in the federal court case, to make any pre-suit demand at all,
upon Xcel Energy’s board of directors. The motions have not yet been ruled upon. Discovery has not commenced.

Newcome v. Xcel Energy Inc.; Barday v. Xcel Energy Inc. On Sept. 23, 2002, and Oct. 9, 2002, two essentially identical actions were filed
in the United States District Court for the District of Colorado, purportedly on behalf of classes of employee participants in Xcel Energy’s
and its predecessors’ 401(k) or ESOP plans from as early as Sept. 23, 1999, forward. The complaints in the actions name as defen-
dants Xcel Energy, its directors, certain former directors and certain of present and former officers. The complaints allege violations
of the Employee Retirement Income Security Act in the form of breach of fiduciary duty in allowing or encouraging purchase, con-
tribution and/or retention of Xcel Energy’s common stock in the plans and making misleading statements and omissions in that regard.
The complaints seek injunctive relief, restitution, disgorgement and other remedial relief, interest and an award of fees and expenses.
The defendants have filed motions to dismiss the complaints upon which no rulings have yet been made. The plaintiffs have made cer-
tain voluntary disclosure of information, but otherwise discovery has not commenced. Upon motion of defendants, the cases have been
transferred to the District of Minnesota for purposes of coordination with the securities class actions and shareholders derivative action
pending there.

Stone & Webster, Inc. v. Xcel Energy Inc. On Oct. 17, 2002, Stone & Webster, Inc. and Shaw Constructors, Inc. filed an action in the
United States District Court in Mississippi against Xcel Energy; Wayne H. Brunetti, chairman, president and chief executive officer;
Richard C. Kelly, president of Xcel Energy Enterprises; NRG and certain NRG subsidiaries. Plaintiffs allege they had a contract with
a single purpose NRG subsidiary for construction of a power generation facility, which was abandoned before completion but after
substantial sums had been spent by plaintiffs. They allege breach of contract, breach of an NRG guarantee, breach of fiduciary duty,
tortious interference with contract, detrimental reliance, misrepresentation, conspiracy and aiding and abetting, and seek to impose
alter ego liability on defendants other than the contracting NRG subsidiary through piercing the corporate veil. The complaint seeks
compensatory damages of at least $130 million plus demobilization and cancellation costs and punitive damages at least treble the
compensatory damages. On Dec. 23, 2003, defendants filed motions to dismiss the complaint, which have not yet been ruled upon.
No trial date has been set in this matter, and Xcel Energy cannot presently predict the outcome of this dispute. Plaintiffs have commenced
what they characterize as jurisdictional discovery, which defendants are resisting.

New York Independent System Operator (NYISO) Claims In November 2002, the NYISO notified NRG of claims related to New York
City mitigation adjustments, general NYISO billing adjustments and other miscellaneous charges related to sales between November 2000
and October 2002. NRG contests both the validity and calculation of the claims and is currently negotiating with the NYISO over the
ultimate disposition. Accordingly, NRG reduced its revenues by $21.7 million and recorded a corresponding reserve for the receivable.

Huntley and Dunkirk Litigation In January 2002, the New York Attorney General and the New York Department of Environmental
Control (NYDEC) filed suit in federal district court in New York against NRG and Niagara Mohawk Power Corp. (NiMo), the prior
owner of the Huntley and Dunkirk facilities in New York. The lawsuit relates to physical changes made at those facilities prior to
NRG’s assumption of ownership. The complaint alleges that these changes represent major modifications undertaken without the
required permits having been obtained. Although NRG has a right to indemnification by the previous owner for fines, penalties, assessments
and related losses resulting from the previous owner’s failure to comply with environmental laws and regulations, NRG could be enjoined
from operating the facilities if the facilities are found not to comply with applicable permit requirements. In addition, NRG could be

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required to bear the costs of installing emissions controls. On March 27, 2003, the court dismissed the complaint against NRG without
prejudice. If the case is litigated to a judgment and there is an unfavorable outcome, NRG has estimated that the total investment that
would be required to install pollution control devices could be as high as $300 million over a 10- to 12-year period. NRG has asserted
that NiMo is obligated to indemnify it for any related compliance costs associated with resolution of the NYDEC enforcement action.

In July 2001, Niagara Mohawk Power Corp. filed a declaratory judgment action in the Supreme Court for the State of New York, County
of Onondaga, against NRG and its wholly owned subsidiaries Huntley Power LLC and Dunkirk Power LLC. Niagara Mohawk Power
Corp. requests a declaration by the court that, pursuant to the terms of the asset sales agreement (ASA) under which NRG purchased the
Huntley and Dunkirk generating facilities from Niagara Mohawk, defendants have assumed liability for any costs for the installation of
emissions controls or other modifications to or related to the Huntley or Dunkirk plants imposed as a result of violations or alleged
violations of environmental law. Niagara Mohawk Power Corporation also requests a declaration by the court that, pursuant to the
ASA, defendants have assumed all liabilities, including liabilities for natural resource damages, arising from emissions or releases of
pollutants from the Huntley and Dunkirk plants, without regard to whether such emissions or releases occurred before, on or after
the closing date for the purchase of the Huntley and Dunkirk plants. NRG has counterclaimed against Niagara Mohawk Power Corp.,
and the parties have exchanged discovery requests.

On Oct. 2, 2000, plaintiff NiMo commenced an action against NRG to recover net damages through the date of judgment, as well as
any additional amounts due and owing for electric service provided to the Dunkirk plant after Sept. 18, 2000. NiMo claims that NRG
has failed to pay retail tariff amounts for utility services commencing on or about June 11, 1999, and continuing to Sept. 18, 2000, and
thereafter. On Aug. 9, 2002, the parties filed a stipulation consolidating this action with two other actions against the Huntley and Oswego
subsidiaries of NRG. On Oct. 8, 2002, a Stipulation and Order was filed in the Erie County Clerk’s Office staying this action pending
submission of some or all of the disputes in the action to the FERC. NRG cannot make an evaluation of the likelihood of an unfavorable
outcome. The cumulative potential loss could exceed $35 million.

other contingencies
Operating Contingency As discussed in Note 19, NSP-Minnesota is experiencing uncertainty regarding its ability to store used nuclear
fuel from its Prairie Island and Monticello nuclear generating facilities. These facilities store used nuclear fuel in a storage pool or dry
cask storage on the plant site, pending the availability of a DOE high-level radioactive substance storage or permanent disposal facility,
or a private interim storage facility.

The Prairie Island plant is licensed by the federal Nuclear Regulatory Commission (NRC) to store up to 48 casks of spent fuel at the
plant. In 1994, the Minnesota Legislature adopted a limit on dry cask storage of 17 casks for the entire state. The 17 casks, which stand
outside the Prairie Island plant, are now full, and under the current configuration, the storage pool within the plant would be full by
2007. Prairie Island cannot operate beyond 2007 unless the existing spent fuel is moved or the storage capacity is increased. Because the
17-cask limit is a statewide limit, the Monticello plant cannot, under current state law, store spent fuel in dry casks. Monticello’s on-site
storage pool is expected to be full in 2010. Monticello cannot operate beyond 2010 unless the existing spent fuel is moved or the storage
capacity is increased. Capitalized costs for Prairie Island and Monticello are being depreciated over these available storage periods, and
no unamortized plant investment is expected to remain if the plants must shut down in 2007 and 2010, respectively.

Due to the investment decisions required to be made in conjunction with the continued efficient operation of the nuclear plants, as well
as the time and cost involved to develop alternatives to the existing nuclear power generation, NSP-Minnesota believes a decision is
necessary in 2003 by the Minnesota Legislature whether the state will allow the continued use of nuclear power in the future. Prairie
Island will only be able to continue operating beyond 2007 with legislative authorization of additional storage space. If additional
storage space for continued operations is not authorized, and interim storage is not available, legislation may be required to ensure
expedited siting and permitting of new generation or transmission facilities in time to replace the power supply currently provided
from NSP-Minnesota’s nuclear plants.

NSP-Minnesota has developed replacement power options, including purchasing new coal or natural gas generation sources. The
feasibility of supplementing new generation sources with additional wind turbines has been reviewed. These options have been presented
to the 2003 Minnesota Legislature. Each option involves a balance of cost, environmental impacts and production efficiencies.
Based on the review of these options, NSP-Minnesota believes the most reliable, lowest-cost, emissions-free method to provide the
needed 1,700 megawatts of energy is to continue to operate the nuclear power plants at Prairie Island and Monticello, which is
possible only with the additional approved storage capacity for spent fuel, either on-site or in a private facility. We cannot predict
at this time what resource decisions the Minnesota Legislature or MPUC may make regarding the continued use of NSP-Minnesota’s
Prairie Island and Monticello nuclear plants. If decisions are not made that allow the plants’ use beyond the storage capacity period,
additional costs may need to be incurred to provide replacement power, either from new generating plants or from purchased power.
The amount of such additional costs, and the level of corresponding rate recovery provided, are not determinable at this time but
may be material.

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Tax Matters PSCo’s wholly owned subsidiary PSR Investments, Inc. (PSRI) owns and manages permanent life insurance policies on
PSCo employees, known as corporate-owned life insurance (COLI). At various times, we have made borrowings against the cash values
of these COLI policies and deducted the interest expense on these borrowings. The IRS had issued a Notice of Proposed Adjustment
proposing to disallow interest expense deductions taken in tax years 1993 through 1997 related to COLI policy loans. A request for
technical advice from the IRS National Office with respect to the proposed adjustment had been pending. Late in 2001, Xcel Energy
received a technical advice memorandum from the IRS National Office, which communicated a position adverse to PSRI. Consequently,
we expect the IRS examination division to begin the process of disallowing the interest expense deductions for the tax years 1993
through 1997.

After consultation with tax counsel, it is Xcel Energy’s position that the IRS determination is not supported by the tax law. Based
upon this assessment, management continues to believe that the tax deduction of interest expense on the COLI policy loans is in full
compliance with the tax law. Therefore, Xcel Energy intends to challenge the IRS determination, which could require several years to
reach final resolution. Although the ultimate resolution of this matter is uncertain, management continues to believe the resolution
of this matter will not have a material adverse impact on Xcel Energy’s financial position, results of operations or cash flows. For
this reason, PSRI has not recorded any provision for income tax or interest expense related to this matter and has continued to take
deductions for interest expense related to policy loans on its income tax returns for subsequent years. However, defense of Xcel Energy’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 of 1993 through 1997, as proposed by the IRS, is approximately
$175 million. Additional interest expense deductions for the period 1998 through 2002 are estimated to total approximately $317 million.
Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2002, would reduce earnings by an estimated
$214 million after tax.

Seren At Dec. 31, 2002, Xcel Energy’s investment in Seren was approximately $255 million. Seren had capitalized $290 million for
plant in service and had incurred another $21 million for construction work in progress for these systems. The construction of its
broadband communications network in Minnesota and California has resulted in consistent losses. Management currently intends to
hold and operate Seren, and believes that no asset impairment exists. Xcel Energy projects improvements in Seren’s operating results,
with positive cash flows in 2005 and an earnings contribution anticipated in 2008.

Xcel Energy International At Dec. 31, 2002, Xcel Energy’s investment in Argentina, through Xcel Energy International, was approximately
$112 million. In December 2002, a subsidiary of Xcel Energy 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 full recovery of Xcel International’s investment. An impairment write-down
of approximately $13 million was recorded in the fourth quarter of 2002.

19. nuclear obligations

Fuel Disposal NSP-Minnesota is responsible for temporarily storing used or spent nuclear fuel from its nuclear plants. The DOE is
responsible for permanently storing spent fuel from NSP-Minnesota’s nuclear plants as well as from other U.S. nuclear plants. NSP-
Minnesota has funded its portion of the DOE’s permanent disposal program since 1981. The fuel disposal fees are based on a charge
of 0.1 cent per kilowatt-hour sold to customers from nuclear generation. Fuel expense includes DOE fuel disposal assessments of
approximately $13 million in 2002, $11 million in 2001 and $12 million in 2000. In total, NSP-Minnesota had paid approximately
$312 million to the DOE through Dec. 31, 2002. However, we cannot determine whether the amount and method of the DOE’s
assessments to all utilities will be sufficient to fully fund the DOE’s permanent storage or disposal facility.

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

NSP-Minnesota has its own temporary, on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants. With
the dry cask storage facilities approved in 1994, management believes it has adequate storage capacity to continue operation of its Prairie
Island nuclear plant until at least 2007. The Monticello nuclear plant has storage capacity to continue operations until 2010. Storage
availability to permit operation beyond these dates is not assured at this time. We are investigating all of the alternatives for spent fuel
storage until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent nuclear
fuel as part of a consortium of electric utilities. If on-site temporary storage at Prairie Island reaches approved capacity, we could seek
interim storage at this or another contracted private facility, if available.

Nuclear fuel expense includes payments to the DOE for the decommissioning and decontamination of the DOE’s uranium enrichment
facilities. In 1993, NSP-Minnesota recorded the DOE’s initial assessment of $46 million, which is payable in annual installments from

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1993 to 2008. NSP-Minnesota is amortizing each installment to expense on a monthly basis. The most recent installment paid in 2002
was $4 million; future installments are subject to inflation adjustments under DOE rules. NSP-Minnesota is obtaining rate recovery of
these DOE assessments through the cost-of-energy adjustment clause as the assessments are amortized. Accordingly, we deferred the
unamortized assessment of $21 million at Dec. 31, 2002, as a regulatory asset.

Plant Decommissioning Decommissioning of NSP-Minnesota’s nuclear facilities is planned for the years 2010 through 2022, using the
prompt dismantlement method. We are currently following industry practice by ratably accruing the costs for decommissioning over the
approved cost recovery period and including the accruals in Accumulated Depreciation. Consequently, the total decommissioning cost
obligation and corresponding assets currently are not recorded in Xcel Energy’s Consolidated Financial Statements.

Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974,
respectively, and are licensed to operate until 2013 and 2014, respectively. Once a decision is made by the Minnesota Legislature regarding
interim spent fuel storage facilities, Xcel Energy will make a decision on whether to pursue license renewal for Monticello and Prairie
Island plants. Applications for license renewal must be submitted to the Nuclear Regulatory Commission (NRC) at least five years prior
to license expiration. Preliminary scoping efforts for license renewal of the Monticello plant have begun, including data collection and
review. The Prairie Island license renewal process has not yet begun. Xcel Energy’s decision whether to apply for license renewal approval
could be contingent on incremental plant maintenance or capital expenditures, recovery of which would be expected from customers
through the respective rate recovery mechanisms. Management cannot predict the specific impact of such future requirements, if any, on
its results of operations.

In 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143  “Accounting for Asset Retirement Obligations.” This
statement will require NSP-Minnesota to record its future nuclear plant decommissioning obligations as a liability at fair value with a
corresponding increase to the carrying value of the related long-lived asset. The liability will be increased to its present value each period,
and the capitalized cost will be depreciated over the useful life of the related long-lived asset. If at the end of the asset’s useful life the
recorded liability differs from the actual obligations paid, SFAS No. 143 requires a gain or loss be recognized at that time. However, rate-
regulated entities may recognize a regulatory asset or liability instead, if the criteria for SFAS No. 71 are met. NSP-Minnesota adopted
SFAS No. 143 as required on Jan. 1, 2003. For additional information, see Note 20 to the Consolidated Financial Statements.

Consistent with cost recovery in utility customer rates, we record annual decommissioning accruals based on periodic site-specific cost
studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Funding presumes that
current costs will escalate in the future at a rate of 4.35 percent per year. The total estimated decommissioning costs that will ultimately
be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant recovery
period. This annuity approach uses an assumed rate of return on funding, which is currently 5.5 percent, net of tax, for external funding
and approximately 8 percent, net of tax, for internal funding. Unrealized gains on nuclear decommissioning investments are deferred as
Regulatory Liabilities based on the assumed offsetting against decommissioning costs in current ratemaking treatment.

The MPUC last approved NSP-Minnesota’s nuclear decommissioning study request in April 2000, using 1999 cost data. A new filing
was submitted to the MPUC in October 2002 that requests continuation of the current accrual. Since the timeframe is getting short on
the recovery of the Prairie Island costs, less than five years at the start of 2003, NSP-Minnesota has recommended that the next filing be
submitted in October 2003. The Department of Commerce has recommended that the internal fund, which is currently being transferred
to the external funds, be transferred over a shorter period of time. This proposal would increase the fund cash contribution by approximately
$13 million in 2003, but may not have a statement of operations impact. Although we expect to operate Prairie Island through the end of
each unit’s licensed life, the approved capital recovery would allow for the plant to be fully depreciated, including the accrual and recovery
of decommissioning costs, in 2007. This is about seven years earlier than each unit’s licensed life. The approved recovery period for Prairie
Island has been reduced because of the uncertainty regarding spent-fuel storage. We believe future decommissioning cost accruals will
continue to be recovered in customer rates.

The total obligation for decommissioning currently is expected to be funded 100 percent by external funds, as approved by the MPUC.
Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. The assets held in
trusts as of Dec. 31, 2002, primarily consisted of investments in fixed income securities, such as tax-exempt municipal bonds and U.S.
government securities that mature in one to 20 years, and common stock of public companies. We plan to reinvest matured securities
until decommissioning begins.

page 94

xcel energy inc. and subsidiaries

notes to consolidated financial statements

At Dec. 31, 2002, NSP-Minnesota had recorded and recovered in rates cumulative decommissioning accruals of $662 million. The
following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation at Dec. 31, 2002:

(Thousands of dollars)

Estimated decommissioning cost obligation from most recently approved study (1999 dollars)
Effect of escalating costs to 2002 dollars (at 4.35 percent per year)
Estimated decommissioning cost obligation in current dollars
Effect of escalating costs to payment date (at 4.35 percent per year)
Estimated future decommissioning costs (undiscounted)
Effect of discounting obligation (using risk-free interest rate)
Discounted decommissioning cost obligation
Assets held in external decommissioning trust
Discounted decommissioning obligation in excess of assets currently held in external trust

Decommissioning expenses recognized include the following components:

(Thousands of dollars)

Annual decommissioning cost accrual reported as depreciation expense:

Externally funded
Internally funded (including interest costs)

Interest cost on externally funded decommissioning obligation
Earnings from external trust funds
Net decommissioning accruals recorded

2002

$   958,266
130,573
1,088,839
805,435
1,894,274
(828,087)
1,066,187
617,048
$   449,139

2002

2001

2000

$51,433
(18,797)
(32)
32
$32,636

$51,433
(17,396)
4,535
(4,535)
$34,037

$51,433
(16,111)
5,151
(5,151)
$35,322

Decommissioning and interest accruals are included with Accumulated Depreciation on the Consolidated Balance Sheet. Interest costs and
trust earnings associated with externally funded obligations are reported in Other Nonoperating Income on the statement of operations.

Negative accruals for internally funded portions in 2000, 2001 and 2002 reflect the impacts of the 1999 decommissioning study, which
has approved an assumption of 100-percent external funding of future costs. Previous studies assumed a portion was funded internally;
beginning in 2000, accruals are reversing the previously accrued internal portion and increasing the external portion prospectively.

xcel energy inc. and subsidiaries          page 95

notes to consolidated financial statements

20. regulatory assets and liabilities

Our regulated businesses prepare their Consolidated Financial Statements in accordance with the provisions of SFAS No. 71, as discussed
in Note 1 to the Consolidated Financial Statements. Under SFAS No. 71, regulatory assets and liabilities can be created for amounts that
regulators may allow us to collect, or may require us to pay back to customers in future electric and natural gas rates. Any portion of our
business that is not regulated cannot use SFAS No. 71 accounting. The components of unamortized regulatory assets and liabilities
shown on the balance sheet at Dec. 31 were:

(Thousands of dollars)

AFDC recorded in plant (a)
Conservation programs (a) (e)
Losses on reacquired debt
Environmental costs
Unrecovered electric production costs(d)
Unrecovered natural gas costs (b)
Deferred income tax adjustments 
Nuclear decommissioning costs (c)
Employees’ postretirement benefits other than pension
Employees’ postemployment benefits
Renewable resource costs
State commission accounting adjustments (a)
Other

Total regulatory assets

Investment tax credit deferrals
Unrealized gains from decommissioning investments
Pension costs-regulatory differences
Interest on income tax refunds
Fuel costs, refunds and other
Total regulatory liabilities

Note
Reference

Remaining
Amortization Period

2002

2001

Plant lives
Up to five years
Term of related debt
To be determined
27 months
One to two years
Mainly plant lives
Up to eight years
10 years
One year
To be determined
Plant lives
Various

1
18, 19
1
1
1

13
2

19
13

$154,158
53,860
85,888
30,974
67,709
11,950
18,611
53,567
38,899
–
26,000
19,157
15,630
$576,403

$109,571
112,145
287,615
6,569
2,527
$518,427

$149,591
65,825
95,394
20,169
–
11,316
17,799
68,484
42,942
119
17,500
7,578
5,725
$502,442

$117,257
149,041
215,687
–
1,957
$483,942

(a) Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.
(b) Excludes current portion with expected rate recovery within 12 months of $12 million and $22 million for 2002 and 2001, respectively.
(c) These costs do not relate to NSP-Minnesota’s nuclear plants. They relate to DOE assessments, as discussed previously, and unamortized costs for PSCo’s Fort

St. Vrain nuclear plant decommissioning.

(d) Excludes current portion with expected rate recovery within 12 months of $54 million and $0 million for 2002 and 2001, respectively.
(e) 2001 amount includes accrued conservation incentives expected to be approved for 2001.

This table excludes deferred energy charges expected to be recovered within the next 12 months of $28 million for 2002, and energy
cost recovery expected to be returned to customers within the next 12 months of $26 million for 2001.

SFAS No. 143 In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143 – “Accounting for Asset Retirement
Obligations.” This statement will require Xcel Energy to record its future nuclear plant decommissioning obligations as a liability at fair
value with a corresponding increase to the carrying value of the related long-lived asset. The liability will be increased to its present
value each period, and the capitalized cost will be depreciated over the useful life of the related long-lived asset. If at the end of the asset’s
life the recorded liability differs from the actual obligations paid, SFAS No. 143 requires that a gain or loss be recognized at that time.
However, rate-regulated entities may recognize a regulatory asset or liability instead, if the criteria for SFAS No. 71 – “Accounting for the
Effects of Certain Types of Regulation” are met.

Xcel Energy currently follows industry practice by ratably accruing the costs for decommissioning over the approved cost recovery period
and including the accruals in accumulated depreciation. At Dec. 31, 2002, Xcel Energy recorded and recovered in rates $662 million of
decommissioning obligations and had estimated discounted decommissioning cost obligations of $1.1 billion based on approvals from
the various state commissions, which used a single scenario. However, with the adoption of SFAS No. 143, a probabilistic view of several
decommissioning scenarios was used, resulting in an estimated discounted decommissioning cost obligation of $1.6 billion.

Xcel Energy expects to adopt SFAS No. 143 as required on Jan. 1, 2003. In current estimates for adoption, the initial value of the liability,
including cumulative accretion expense through that date, would be approximately $869 million. This liability would be established by
reclassifying accumulated depreciation of $573 million and by recording two long-term assets totaling $296 million. A gross capitalized
asset of $130 million would be recorded and would be offset by accumulated depreciation of $89 million. In addition, a regulatory asset of
approximately $166 million would be recorded for the cumulative effect adjustment related to unrecognized depreciation and accretion
under the new standard. Management expects that the entire transition amount would be recoverable in rates over time and, therefore,
would support this regulatory asset upon adoption of SFAS No. 143.

page 96

xcel energy inc. and subsidiaries

notes to consolidated financial statements

Xcel Energy has completed a detailed assessment of the specific applicability and implications of SFAS No. 143 for obligations other
than nuclear decommissioning. Other assets that may have potential asset retirement obligations include ash ponds, any generating
plant with a Part 30 license and electric and natural gas transmission and distribution assets on property under easement agreements.
Easements are generally perpetual and require retirement action only upon abandonment or cessation of use of the property for the
specified purpose. The liability is not estimable because Xcel Energy intends to utilize these properties indefinitely. The asset retirement
obligations for the ash ponds and generating plants cannot be reasonably estimated due to an indeterminate life for the assets associated
with the ponds and uncertain retirement dates for the generating plants. Since the time period for retirement is unknown, no liability
would be recorded. When a retirement date is certain, a liability will be recorded.

The adoption of SFAS No. 143 in 2003 will also affect Xcel Energy’s accrued plant removal costs for other generation, transmission and
distribution facilities for its utility subsidiaries. Although SFAS No. 143 does not recognize the future accrual of removal costs as a
generally accepted accounting principles liability, long-standing ratemaking practices approved by applicable state and federal regulatory
commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number
of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were
accrued and the changing of rates through time, we have estimated the amount of removal costs accumulated through historic depreciation
expense based on current factors used in the existing depreciation rates. Accordingly, the estimated amounts of future removal costs, which
are considered regulatory liabilities under SFAS No. 143 that are accrued in accumulated depreciation, are as follows at Dec. 31:

(Millions of dollars)

NSP-Minnesota
NSP-Wisconsin
PSCo
SPS

2002

$304
$ 70
$329
$ 97

21. segments and related information

Xcel Energy has the following reportable segments: Electric Utility, Natural Gas Utility and its nonregulated energy business, NRG.
Previously, e prime was considered a reportable segment due to the significance of its gross trading revenues. However, with the change
in reporting of trading operations to a net basis, as discussed in Note 1 to the Consolidated Financial Statements, e prime is no longer a
reportable segment due to its net trading margins/revenue being below the quantitative thresholds. e prime is included in the All Other
category for all periods presented.

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

– Xcel Energy’s Natural Gas Utility transmits, transports, stores and distributes natural gas and propane primarily in portions of

Minnesota, Wisconsin, North Dakota, Michigan, Arizona, Colorado and Wyoming.

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

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

To report net income for electric and natural gas utility segments, Xcel Energy must assign or allocate all costs and certain other
income. In general, costs are:

– directly assigned wherever applicable;
– allocated based on cost causation allocators wherever applicable; and
– allocated based on a general allocator for all other costs not assigned by the above two methods.

The accounting policies of the segments are the same as those described in Note 1 to the Consolidated Financial Statements. Xcel Energy
evaluates performance by each legal entity based on profit or loss generated from the product or service provided.

xcel energy inc. and subsidiaries          page 97

notes to consolidated financial statements

business segments 

(Thousands of dollars)

2002
Operating revenues from external 

customers (a)
Intersegment revenues
Equity in earnings (losses) of 
unconsolidated affiliates (a)

Total revenues
Depreciation and amortization
Financing costs, mainly interest expense
Income tax expense (credit)
Segment net income (loss)

2001
Operating revenues from external 

customers (a)
Intersegment revenues
Equity in earnings (losses) of 
unconsolidated affiliates (a)

Total revenues
Depreciation and amortization
Financing costs, mainly interest expense
Income tax expense (credit)
Segment income (loss) before 

extraordinary items

Extraordinary items, net of tax
Segment net income (loss)

2000
Operating revenues from external 

customers (a)
Intersegment revenues
Equity in earnings (losses) of 
unconsolidated affiliates (a)

Total revenues
Depreciation and amortization
Financing costs, mainly interest expense
Income tax expense (credit)
Segment income (loss) before 

extraordinary items

Extraordinary items, net of tax
Segment net income (loss)

Electric
Utility

Natural Gas
Utility

NRG (b)

All Other (b)

Reconciling 
Eliminations

Consolidated
Total

$5,437,017
987

$1,397,799
4,949

$ 2,212,153
–

$405,839
165,732

$
–
(171,665)

$  9,452,808 
3

–
$5,438,004
$ 647,491
286,180
301,875
$ 478,711

–
$1,402,748
92,868
$
52,583
53,831
98,517

$

68,996
$ 2,281,149
256,199
$
493,956
(165,382)
$(3,464,282)

2,565
$574,136
$  40,871
131,383
(818,309)
$715,140 

–
$(171,665)
–
$ 
(46,022)
–
$ (46,077)

71,561
$ 9,524,372
$ 1,037,429
918,080
(627,985)
$ (2,217,991)

$6,463,401
978

$2,051,199
4,501 

$ 2,201,427
1,859 

$397,895
178,111

$           –
(183,019)

$11,113,922
2,430

–
$6,464,379
$ 617,320
265,285
351,181

$ 535,182
11,821
$ 547,003

–
$2,055,700
92,989
$
49,108
41,077

210,032
$ 2,413,318
169,596
$
389,311
28,052

$

$

81,562
–
81,562

$

$

265,204
–
265,204

7,038
$583,044
$ 26,398
115,127
(88,939)

$ (56,879)
(1,534)
$ (58,413)

–

$(183,019) 
$           –
(52,055)
–

217,070
$11,333,422
906,303
$
766,776
331,371

$ (40,390)
–
$ (40,390)

$

$

784,679
10,287
794,966

$5,704,683 
1,179

$1,466,478
5,761

$ 1,670,774
2,256 

$195,236
132,347

$           –
(137,962)

$ 9,037,171
3,581

–
$5,705,862
$ 574,018
333,512
261,942

–
$1,472,239
85,353
$
60,755
36,962

139,364
$ 1,812,394
97,304
$
250,790
86,903

$ 340,634
(18,960)
$ 321,674

$

$

57,911
–
57,911

$

$

182,935
–
182,935

43,350
$370,933
$ 10,071
67,696
(86,777)

$ (20,083)
–
$ (20,083)

–

$(137,962) 
$           –
(59,780)
–

182,714
$ 9,223,466
766,746
$
652,973
299,030

$ (15,609)
–
$ (15,609)

$

$

545,788
(18,960)
526,828

(a) 

(Millions of dollars)

2002

2001

2000

NRG

All Other

NRG

All Other

NRG

All Other

Operating revenues from external customers – United States
Operating revenues from external customers – international
Equity in earnings of unconsolidated affiliates – United States
Equity in earnings of unconsolidated affiliates – international
Consolidated earnings (loss) – international

$1,874
338
20
49
(695)

$369
37
3
–
18

$1,886
315
151
59
100

$362
36
6
1
6

$1,575
96
121
18
39

$195
–
8
35
29

NRG’s international assets were $2,368 million and $3,199 million in 2002 and 2001, respectively. NRG’s equity investments and projects outside the United
States were $310 million and $417 million in 2002 and 2001, respectively.

All Other’s international assets were $69 million and $138 million in 2002 and 2001, respectively. All Other’s investments and projects outside the United States
were $0 and $37 million in 2002 and 2001, respectively.

(b) NRG segment represents the consolidated results of NRG excluding the earnings attributable to minority shareholders of NRG prior to June 2002, when

Xcel Energy acquired a 100-percent ownership in NRG. All Other includes minority interest income (expense) related to NRG of $13.6 million in 2002,
$(65.6) million in 2001, and $(29.2) million in 2000. Also, in 2002, All Other includes income tax benefits related to Xcel Energy’s investment in NRG
of $706 million, as discussed in Note 11 to the Consolidated Financial Statements.

page 98

xcel energy inc. and subsidiaries

notes to consolidated financial statements

22. summarized quarterly financial data (unaudited)

Subsequent to the issuance of Xcel Energy’s financial statements for the quarter ended Sept. 30, 2002, NRG’s management determined
that the accounting for certain transactions required revision.

NRG determined that it had misapplied the provisions of SFAS No. 144 related to asset grouping in connection with the review
for impairment of its long-lived assets during the quarter ended Sept. 30, 2002. SFAS No. 144 requires that for purposes of testing
recoverability, assets be grouped at the lowest level for which identifiable cash flows are largely independent of the cash flows of
other assets. NRG recalculated the asset impairment tests in accordance with SFAS No. 144 using the appropriate asset grouping for
independent cash flows for each generation facility. As a result, NRG concluded that asset impairments should have been recorded
for two projects known as Bayou Cove Peaking Power LLC and Somerset Power LLC. Since NRG concluded that the “triggering
events” that led to the impairment charge were experienced in the third quarter of 2002, the asset impairments related to these projects
should have been recorded as of Sept. 30, 2002. NRG calculated the asset impairment charges for Bayou Cove Peaking Power LLC
and Somerset Power LLC to be $126.5 million and $49.3 million, respectively.

In connection with NRG’s year-end audit, two additional items were found to be inappropriately recorded as of Sept. 30, 2002. These
items included the inappropriate treatment of interest rate swap transactions as cash flow hedges and the decrease in the value of a bond
remarketing option from the original price paid by NRG. The error correction for the interest rate swaps resulted in the recording of
additional income of $61.6 million as of Sept. 30, 2002. The recognition of the decrease in the value of the remarketing option resulted
in a charge to income of $15.9 million as of Sept. 30, 2002.

A summary of the significant effects of the restatement, including the impact of fourth quarter discontinued operations decisions, on
Xcel Energy’s consolidated statements of operations for the three and nine months ended Sept. 30, 2002, is as follows:

(Thousands of dollars, except per share amounts)

Consolidated Statements of Operations
Revenue 
Operating income
Income (loss) from continuing operations
Discontinued operations – income (loss)
Net income (loss)
Earnings (loss) available for common shareholders
Earnings (loss) per share from continuing operations – basic and diluted
Earnings (loss) per share discontinued operations – basic and diluted
Earnings per share – basic and diluted

As Previously Reported

As Restated

Three Months
Ended

Nine Months
Ended

Three Months
Ended

Nine Months
Ended

$ 2,473,331
(1,948,725)
(1,496,959)
(577,001)
(2,073,960)
(2,075,020)
$        (3.77)
$        (1.45)
$        (5.22)

$ 7,070,824
(1,334,201)
(1,317,413)
(565,741)
(1,883,154)
(1,886,334)
$        (3.51)
$        (1.50)
$        (5.01)

$ 2,473,331
(2,140,418)
(1,627,039)
(577,001)
(2,204,040)
(2,205,100)
$        (4.10)
$        (1.45)
$        (5.55)

$ 7,070,824
(1,525,894)
(1,447,493)
(565,741)
(2,013,234)
(2,016,414)
$        (3.85)
$        (1.50)
$        (5.35)

During the fourth quarter of 2002, NRG determined that it had inadvertently offset its investment in Jackson County, Miss., bonds in
the amount of $155.5 million against long-term debt of the same amount owed to the County. This resulted in an understatement of
NRG’s assets and liabilities by $155.5 million as of Sept. 30, 2002. In addition, the restatement for Bayou Cove Peaking LLC and
Somerset Power LLC impairments reduced the previously reported net property, plant and equipment balance by $175.8 million.
The restatement for the interest rate swaps had no impact on total shareholder’s equity and the restatement for the remarketing
option reduced other assets by $15.9 million.

Summarized quarterly unaudited financial data is as follows:

(Thousands of dollars, except per share amounts)

Quarter Ended

March 31, 2002
(a)

June 30, 2002
(a)

Sept. 30, 2002
(a) (d)
As Restated

Dec. 31, 2002
(a)

Revenue (c)
Operating income (loss)
Income (loss) from continuing operations
Discontinued operations – income (loss)
Net income (loss)
Earnings (loss) available for common shareholders
Earnings (loss) per share from continuing operations – basic and diluted
Earnings (loss) per share discontinued operations – basic and diluted
Earnings (loss) per share total – basic and diluted

$2,370,584 
298,977 
93,929 
9,575 
103,504
102,444 
$         0.26 
$         0.03
$         0.29 

$2,226,909 
315,548 
85,617 
1,685 
87,302 
86,242 
0.22 
–
0.22 

$
$
$

$ 2,473,331 
(2,140,418)
(1,627,039)
(577,001)
(2,204,040)
(2,205,100)
$        (4.10)
$        (1.45)
$        (5.55)

$2,453,548
93,562
(213,877)
9,120
(204,757)
(205,818)
$       (0.54)
$
0.02
$       (0.52)

xcel energy inc. and subsidiaries          page 99

notes to consolidated financial statements

(Thousands of dollars, except per share amounts)

Revenue (c)
Operating income 
Income from continuing operations before extraordinary items
Discontinued operations – income (loss)
Extraordinary items – income
Net income
Earnings available for common shareholders
Earnings per share from continuing operations 

before extraordinary items – basic and diluted

Earnings per share discontinued operations – basic and diluted
Earnings per share extraordinary items – basic and diluted
Earnings per share – basic and diluted

March 31, 2001

June 30, 2001
(b)

Sept. 30, 2001

Dec. 31, 2001
(b)

Quarter Ended

$3,174,066
461,097
191,974
17,336
–
209,310
208,250

$
$
$
$

0.56
0.05
–
0.61

$2,743,822
416,843
162,654
5,203
–
167,857
166,797

$2,931,799
635,884
264,823
8,080
–
272,903
271,843

$
$
$
$

0.47
0.02
–
0.49

$
$
$
$

0.77
0.02
–
0.79

$2,483,735
344,323
118,236
16,373
10,287
144,896
143,835

$
$
$
$

0.34
0.05
0.03
0.42

(a) 2002 results include special charges and unusual items in all quarters, as discussed in Note 2 to the Consolidated Financial Statements.

– First-quarter results were decreased by $9 million, or 1 cent per share, for a special charge related to utility/service company employee restaffing costs, and by

$5 million, or 1 cent per share, for regulatory recovery adjustments at SPS.

– Second-quarter results were decreased by $36 million, or 9 cents per share, for NEO-related special charges taken by NRG.
– Third-quarter results (as restated) were decreased by $2.5 billion, or $5.97 per share, for special charges related to NRG asset impairments and financial

restructuring, and were increased by $676 million, or $1.77 per share, due to estimated tax benefits related to Xcel Energy’s investment in NRG.

– Fourth-quarter results were decreased by $100 million, or 24 cents per share, for special charges related to NRG asset impairments and financial restructuring

costs, and increased by $30 million, or $0.08 per share, due to revisions to the estimated tax benefits related to Xcel Energy’s investment in NRG.
(b) 2001 results include special charges and unusual items in the second and fourth quarters, as discussed in Note 2 to the Consolidated Financial Statements.

– Second-quarter results were increased by $41 million, or 7 cents per share, for conservation incentive adjustments, and decreased by $23 million, or 4 cents

per share, for a special charge related to postemployment benefits.

– Fourth-quarter results were decreased by $39 million, or 7 cents per share, for a special charge related to employee restaffing costs.

(c) Certain items in the 2001 and 2002 quarterly income statements have been reclassified to conform to the 2002 annual presentation. These reclassifications
included the netting of trading revenues and expenses previously reported gross, and NRG’s discontinued operations, as discussed in Notes 1 and 3 to the
Consolidated Financial Statements, respectively.

(d) Third-quarter 2002 results for NRG have been restated from amounts previously reported. NRG’s asset impairments and restructuring charges for the quarter have
been restated, increasing NRG’s operating expenses by $192 million and a correction for interest rate swaps that resulted in additional income of $62 million,
for a net effect of $130 million in additional loss for the quarter. As a result, Xcel Energy’s Special Charges included in operating expenses for the quarter ended
Sept. 30, 2002, increased by $192 million, or $0.50 per share.

page 100

xcel energy inc. and subsidiaries

shareholder information and fiscal agents

shareholder information

headquarters
800 Nicollet Mall, Minneapolis, Minnesota 55402

internet address
www.xcelenergy.com

investors hotline
1-877-914-9235

stock transfer agent
Wells Fargo Shareowner Services
161 North Concord Exchange
South St. Paul, Minnesota 55075

1-877-778-6786, toll free
This is an automated phone system to expedite requests. However, staying on the line to speak with a representative is an option.
Representatives are available from 7 a.m. to 7 p.m. CST.

xcel energy direct purchase plan
Xcel Energy’s Direct Purchase Plan, offered by prospectus, is a convenient way to purchase shares of Xcel Energy’s common stock
without payment of any brokerage commission or service charge. Contact Xcel Energy Shareholder Services at 1-877-914-9235.

reports available online
Financial reports, including filings with the Securities and Exchange Commission and Xcel Energy’s Report to Shareholders, are
available online at www.xcelenergy.com.

stock exchange listings and ticker symbol
Common stock is listed on the New York, Chicago and Pacific exchanges under the ticker symbol XEL. The New York Stock
Exchange lists some of Xcel Energy’s preferred stock. In newspaper listings, it appears as XcelEngy.

investor relations
Internet address: www.xcelenergy.com or contact Richard Kolkmann, Managing Director, Investor Relations, at 612-215-4559 
or Paul Johnson, Director, Investor Relations, at 612-215-4535.

shareholder services
Internet address: www.xcelenergy.com or contact Dianne Perry, Manager, Shareholder Services, at 612-215-4534 or e-mail:
dianne.g.perry@xcelenergy.com.

fiscal agents

xcel energy inc.
Transfer Agent, Registrar, Dividend Distribution, Common and Preferred Stocks 
Wells Fargo Bank Minnesota, N.A., 161 North Concord Exchange, South St. Paul, Minnesota 55075

Trustee – Bonds
Wells Fargo Bank Minnesota, N.A., Sixth Street and Marquette Avenue, Minneapolis, Minnesota 55479-0059

Coupon Paying Agents – Bonds
Wells Fargo Bank Minnesota, N.A., Minneapolis, Minnesota

xcel energy inc. and subsidiaries          page 101

Wayne H. Brunetti *
Chairman, President and CEO
Xcel Energy Inc.

C. Coney Burgess 2, 3
Chairman and President
Burgess-Herring Ranch Company

David A. Christensen 2, 4
Retired President and CEO
Raven Industries, Inc.

Roger R. Hemminghaus 1, 4
Retired Chairman and CEO
Ultramar Diamond Shamrock 
Corporation

A. Barry Hirschfeld 2, 3
President 
A.B. Hirschfeld Press, Inc.

xcel energy directors

Douglas W. Leatherdale 2, 3
Retired Chairman and CEO
The St. Paul Companies, Inc.

Albert F. Moreno 1, 4
Senior Vice President and 
General Counsel 
Levi Strauss & Co.

Rodney E. Slifer 1, 4
Partner
Slifer, Smith & Frampton

W. Thomas Stephens 2, 3
Retired President and CEO
MacMillan Bloedel, Ltd.

Dr. Margaret R. Preska 1, 3
President Emerita
Minnesota State University – Mankato
Distinguished Service Professor
Minnesota State Universities

Board Committees:
1. Audit
2. Compensation and Nominating
3. Finance
4. Operations and Nuclear

* Wayne H. Brunetti is an ex officio member 

of all committees.

A. Patricia Sampson 2, 4
President and CEO
The Sampson Group, Inc.

Allan L. Schuman 1, 3
Chairman and CEO
Ecolab, Inc.

xcel energy principal officers

Paul J. Bonavia
President – Energy Markets

Wayne H. Brunetti
Chairman, President and 
Chief Executive Officer

Benjamin G.S. Fowke III
Vice President and Treasurer

Raymond E. Gogel
Vice President and Chief
Information Officer

Cathy J. Hart
Vice President and 
Corporate Secretary

Gary R. Johnson
Vice President and 
General Counsel

Richard C. Kelly
Vice President and Chief
Financial Officer

Cynthia L. Lesher
Vice President and Chief
Administrative Officer

Tom Petillo
President – Delivery

David E. Ripka
Vice President and Controller

Patricia K. Vincent
President – Retail

David M. Wilks
President – Energy Supply

page 102

xcel energy inc. and subsidiaries

U.S. Bancorp Center
800 Nicollet Mall
Minneapolis, MN 55402
Xcel Energy investors hotline: 1-877-914-9235
www.xcelenergy.com

© 2003 Xcel Energy Inc.
Xcel Energy is a trademark of Xcel Energy Inc.
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