XCEL ENERGY INC - 10-Q Quarterly Report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

(EXCEL ENERGY(SM) LOGO)

FORM 10-Q


þ		Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934


o		Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For Quarter Ended September 30, 2002

Commission File Number 1-3034

Xcel Energy Inc.

(Exact name of registrant as specified in its charter)


Minnesota (State or other jurisdiction of incorporation or organization)		41-0448030 (I.R.S. Employer Identification No.)

800 Nicollet Mall, Minneapolis, Minn. (Address of principal executive offices)		55402 (Zip Code)

Registrant’s telephone number, including area code (612) 330-5500

Former name, former address and former fiscal year, if changed since last report

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.


Class		Outstanding at Oct. 31, 2002

Common Stock, $2.50 par value		398,714,039 shares

TABLE OF CONTENTS


PART 1. FINANCIAL INFORMATION
		CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
		CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
		CONSOLIDATED BALANCE SHEETS (UNAUDITED)
		CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
	Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
	Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	Item 4. CONTROLS AND PROCEDURES
Part II. OTHER INFORMATION
	Item 1. LEGAL PROCEEDINGS
	Item 3. DEFAULTS UPON SENIOR SECURITIES
	Item 6. EXHIBITS AND REPORTS ON FORM 8-K
SIGNATURES
CERTIFICATIONS
EX-4.01 Supplemental Indenture dated Aug. 15, 2002
EX-4.02 Supplemental Indenture dated Sept 15, 2002
EX-4.03 Supplemental Indenture dated Aug. 15, 2002
EX-4.04 Supplemental Indenture dated Sept 15, 2002
EX-4.05 Supplemental Indenture dated June 1, 2002
EX-4.06 Supplemental Indenture dated July 1, 2002
EX-4.10 Form of First Notes
EX-4.11 Form of Second Notes
EX-4.12 Form of First Call Notes
EX-4.13 Form of Second Call Notes
EX-4.14 Form of Third Notes
EX-4.15 Form of Third Call Notes
EX-99.01 Statement pursuant to Private Securities
EX-99.1 Certification Pursuant to 18 USC Sec. 1350

PART 1. FINANCIAL INFORMATION

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(Thousands of Dollars, Except Per Share Data)


				Three Months Ended					Nine Months Ended
				Sept. 30					Sept. 30

				2002			2001		2002			2001

Operating revenues:
	Electric utility			$	1,556,942		$	1,818,812	$	4,117,497		$	5,010,201
	Gas utility				138,268			216,589		937,814			1,577,159
	Electric and gas trading margin				2,127			9,341		4,472			91,333
	Nonregulated and other				810,782			825,876		2,107,849			2,102,118
	Equity earnings from investments in affiliates				27,970			111,021		73,139			198,526

		Total operating revenues			2,536,089			2,981,639		7,240,771			8,979,337
Operating expenses:
	Electric fuel and purchased power — utility				618,442			947,914		1,650,961			2,572,456
	Cost of gas sold and transported — utility				58,115			135,734		559,347			1,199,888
	Cost of sales — nonregulated and other				454,505			379,636		1,137,133			1,132,376
	Other operating and maintenance expenses — utility				352,863			382,299		1,088,337			1,124,971
	Other operating and maintenance expenses — nonregulated				197,369			200,778		571,862			463,389
	Depreciation and amortization				270,899			243,797		792,118			671,818
	Taxes (other than income taxes)				87,538			53,894		255,143			236,395
	Special charges (see Note 2)				2,908,347			—		2,978,828			23,018
	Writedowns and disposal losses from investments (see Notes 2 and 3)				128,967			—		133,135			—

			Total operating expenses		5,077,045			2,344,052		9,166,864			7,424,311

Operating income (loss)					(2,540,956	)		637,587		(1,926,093	)		1,555,026
Interest and other nonoperating income— net of other expenses					5,394			19,926		38,679			46,273
Interest charges and financing costs:
	Interest charges — net of amounts capitalized				236,141			203,653		640,925			555,430
	Distributions on redeemable preferred securities of subsidiary trusts				9,586			9,700		28,758			29,100

			Total interest charges and financing costs		245,727			213,353		669,683			584,530

Income (loss) from continuing operations before income taxes and minority interest					(2,781,289	)		444,160		(2,557,097	)		1,016,769
Income taxes (benefit)					(687,955	)		148,131		(616,934	)		324,573
Minority interest (income) expense					(26,129	)		37,210		(39,184	)		57,108

Income (loss) from continuing operations					(2,067,205	)		258,819		(1,900,979	)		635,088
Income (loss) from discontinued operations, net of tax (see Note 3)					(6,755	)		14,084		17,825			14,982

Net income (loss)					(2,073,960	)		272,903		(1,883,154	)		650,070
Dividend requirements on preferred stock					1,060			1,060		3,180			3,180

Earnings (loss) available for common shareholders				$	(2,075,020	)	$	271,843	$	(1,886,334	)	$	646,890

Weighted average common shares outstanding (in thousands):
	Basic				397,405			343,770		376,565			342,378
	Diluted				397,405			344,385		376,565			343,188
Earnings per share — basic — Income (loss) from continuing operations				$	(5.20	)	$	0.75	$	(5.06	)	$	1.85
Discontinued Operations					(0.02	)		0.04		0.05			0.04

Earnings per share — basic				$	(5.22	)	$	0.79	$	(5.01	)	$	1.89

Earnings per share — diluted — Income (loss) from continuing operations				$	(5.20	)	$	0.75	$	(5.06	)	$	1.84
Discontinued Operations					(0.02	)		0.04		0.05			0.04

Earnings per share — diluted				$	(5.22	)	$	0.79	$	(5.01	)	$	1.88

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)


				Nine Months Ended Sept. 30

				2002			2001

Operating activities:
	Net (loss) income			$	(1,883,154	)	$	650,070
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			800,648			715,493
		Nuclear fuel amortization			37,208			31,843
		Deferred income taxes			(849,327	)		(34,193	)
		Amortization of investment tax credits			(10,285	)		(9,684	)
		Allowance for equity funds used during construction			(5,125	)		(6,373	)
		Undistributed equity in earnings of unconsolidated affiliates			(14,544	)		(170,900	)
		Write-downs and losses from investments and disposal of discontinued operations			150,234			—
		Non-cash special charges — primarily asset impairment write-downs			2,961,454			—
		Gain on sale of property			(6,785	)		—
		Unrealized (gain) loss on derivative financial instruments			15,106			13,942
		Change in accounts receivable			(32,686	)		155,090
		Change in inventories			32,981			(123,826	)
		Change in other current assets			146,473			354,756
		Change in accounts payable			81,847			(495,896	)
		Change in other current liabilities			150,831			258,220
		Change in other assets and liabilities			(75,943	)		(994	)

			Net cash provided by operating activities		1,498,933			1,337,548
Investing activities:
	Nonregulated capital expenditures and asset acquisitions				(1,443,999	)		(3,901,094	)
	Utility capital/construction expenditures				(696,092	)		(753,572	)
	Proceeds from sale of property				40,465			—
	Allowance for equity funds used during construction				5,125			6,373
	Investments in external decommissioning fund				(175,356	)		(46,865	)
	Equity investments, loans, deposits and sales of nonregulated projects				(129,464	)		82,194
	Collection of loans made to nonregulated projects				21,081			3,821
	Other investments — net				76,086			(14,205	)

		Net cash used in investing activities			(2,302,154	)		(4,623,348	)
Financing activities:
	Short-term borrowings — net				(172,047	)		737,880
	Proceeds from issuance of long-term debt				2,318,152			2,854,213
	Repayment of long-term debt, including reacquisition premiums				(510,899	)		(422,936	)
	Proceeds from issuance of common stock				570,242			108,609
	Proceeds from NRG stock offering				—			474,348
	Dividends paid				(420,560	)		(388,491	)

		Net cash provided by financing activities			1,784,888			3,363,623
Effect of exchange rates on cash and cash equivalents					5,979			8,173
Net increase in cash and cash equivalents					987,646			85,996
Cash and cash equivalents at beginning of year					277,356			216,491

Cash and cash equivalents at end of period				$	1,265,002		$	302,487

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)


			Sept. 30, 2002			Dec. 31, 2001

ASSETS
Current assets:
	Cash and cash equivalents		$	1,265,002		$	277,356
	Restricted cash			208,277			143,009
	Accounts receivable — net of allowance for bad debts of $48,142 and $46,815, respectively			1,049,330			1,075,686
	Accrued unbilled revenues			359,937			495,994
	Materials and supplies inventories — at average cost			333,719			323,505
	Fuel inventory — at average cost			196,328			250,043
	Gas inventories — replacement cost in excess of (below) LIFO: $(41,165) and $11,331, respectively			140,101			126,563
	Recoverable purchased gas and electric energy costs			65,782			52,583
	Derivative instruments valuation — at market			79,839			59,790
	Prepayments and other			303,838			309,554
	Current assets held for sale			192,135			180,413

		Total current assets		4,194,288			3,294,496

Property, plant and equipment, at cost:
	Electric utility plant			16,375,000			16,099,655
	Nonregulated property and other			8,751,511			7,783,994
	Gas utility plant			2,568,036			2,493,028
	Construction work in progress (utility amounts of $890,841 and $669,895, respectively)			1,533,727			3,682,619

		Total property, plant and equipment		29,228,274			30,059,296
	Less: accumulated depreciation			(10,145,971	)		(9,536,854	)
	Nuclear fuel — net of accumulated amortization of $1,047,063 and $1,009,855, respectively			53,295			96,315

		Net property, plant and equipment		19,135,598			20,618,757

Other assets:
	Investments in unconsolidated affiliates			1,141,107			1,209,017
	Notes receivable, including amounts from affiliates of $201,268 and $202,411, respectively			812,370			779,186
	Nuclear decommissioning fund and other investments			732,363			690,734
	Regulatory assets			569,840			502,442
	Derivative instruments valuation — at market			255,606			179,683
	Prepaid pension asset			509,122			378,825
	Goodwill — net (See Note 1)			40,150			63,925
	Intangible assets — net (See Note 1)			62,027			53,369
	Other			402,417			363,551
	Noncurrent assets held for sale			550,887			584,211

		Total other assets		5,075,889			4,804,943

		Total assets	$	28,405,775		$	28,718,196


			Sept. 30, 2002		Dec. 31, 2001

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	7,521,934	$	419,335
	Short-term debt			2,004,120		2,224,812
	Accounts payable			1,408,852		1,319,770
	Taxes accrued			377,951		246,152
	Dividends payable			75,982		130,845
	Derivative instruments valuation — at market			48,422		83,122
	Other			716,395		698,315
	Current liabilities held for sale			296,929		310,810

		Total current liabilities		12,450,585		5,433,161

Deferred credits and other liabilities:
	Deferred income taxes			1,407,927		2,270,854
	Deferred investment tax credits			172,816		184,148
	Regulatory liabilities			497,274		483,942
	Derivative instruments valuation — at market			119,303		42,445
	Benefit obligations and other			741,948		703,836
	Noncurrent liabilities held for sale			240,895		279,748

		Total deferred credits and other liabilities		3,180,163		3,964,973

Minority interest in subsidiaries				38,837		636,847
Capitalization:
	Long-term debt			6,889,364		11,889,418
	Mandatorily redeemable preferred securities of subsidiary trusts			494,000		494,000
	Preferred stockholders’ equity — authorized 7,000,000 shares, of $100 par value; outstanding shares: 1,049,800			105,320		105,320
	Common stockholders’ equity — authorized 1,000,000,000 shares of $2.50 par value; outstanding shares: 2002, 398,714,039; 2001, 345,801,028			5,247,506		6,194,477
Commitments and Contingent Liabilities (see Note 9)
		Total Liabilities and Equity	$	28,405,775	$	28,718,196

See Notes to Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)

Three Months Ended Sept. 30, 2002 and 2001

(Thousands of Dollars)


												Accumulated
												Other				Total
						Retained			Shares Held			Comprehensive			Stockholders'
		Par Value		Premium		Earnings			by ESOP			Income				Equity

Balance at June 30, 2001		$	860,211	$	2,924,429	$	2,401,727		$	(21,502	)	$	(141,000	)		$	6,023,865

Net income							272,903										272,903
Currency translation adjustments													39,066				39,066
After-tax net unrealized losses related to derivatives accounted for as hedges (see Note 11)													(39,068	)			(39,068	)
After-tax net unrealized losses on derivative transactions reclassified into earnings (see Note 11)													12,358				12,358

Comprehensive income for the period																	285,259
Dividends declared:
	Cumulative preferred stock of Xcel Energy						(1,060	)									(1,060	)
	Common stock						(129,343	)									(129,343	)
Issuances of common stock — net			2,076		22,894												24,970
Other							17										17
Repayment of ESOP loan ^(a)										1,444							1,444

Balance at Sept. 30, 2001		$	862,287	$	2,947,323	$	2,544,244		$	(20,058	)	$	(128,644	)		$	6,205,152

Balance at June 30, 2002		$	992,186	$	4,019,732	$	2,459,374		$	(16,881	)	$	(82,125	)		$	7,372,286

Net income							(2,073,960	)									(2,073,960	)
Currency translation adjustments													(31,515	)			(31,515	)
After-tax net unrealized gains related to derivatives accounted for as hedges (see Note 11)													54,284				54,284
After-tax net unrealized gains on derivative transactions reclassified into earnings (see Note 11)													(17,707	)			(17,707	)
Unrealized gain-marketable securities													(1	)			(1	)

Comprehensive income for the period																	(2,068,899	)
Dividends declared:
	Cumulative preferred stock of Xcel Energy						(1,060	)									(1,060	)
	Common stock						(74,813	)									(74,813	)
Issuances of common stock — net			4,435		15,274												19,709
Other							90						(8	)			82
Repayment of ESOP loan ^(a)										201							201

Balance at Sept. 30, 2002		$	996,621	$	4,035,006	$	309,631		$	(16,680	)	$	(77,072	)		$	5,247,506

(a)

Did not affect cash flows

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)

Nine Months Ended Sept. 30, 2002 and 2001

(Thousands of Dollars)


												Accumulated
												Other			Total
						Retained			Shares Held			Comprehensive			Stockholders'
		Par Value		Premium		Earnings			by ESOP			Income			Equity

Balance at Dec. 31, 2000		$	852,085	$	2,607,025	$	2,284,220		$	(24,617	)	$	(156,929	)	$	5,561,784

Net income							650,070									650,070
Currency translation adjustments													17,604			17,604
Cumulative effect of accounting change -SFAS 133													(28,780	)		(28,780	)
After-tax net unrealized gains related to derivatives accounted for as hedges (see Note 11)													7,230			7,230
After-tax net unrealized losses on derivative transactions reclassified into earnings (see Note 11)													32,231			32,231

Comprehensive income for the period																678,355
Dividends declared:
	Cumulative preferred stock of Xcel Energy						(3,180	)								(3,180	)
	Common stock						(386,840	)								(386,840	)
Issuances of common stock — net			10,202		98,407											108,609
Other							(26	)								(26	)
Gain recognized from NRG stock offering					241,891											241,891
Repayment of ESOP loan ^(a)										4,559						4,559

Balance at Sept. 30, 2001		$	862,287	$	2,947,323	$	2,544,244		$	(20,058	)	$	(128,644	)	$	6,205,152

Balance at Dec. 31, 2001		$	864,503	$	2,969,589	$	2,558,403		$	(18,564	)	$	(179,454	)	$	6,194,477

Net income							(1,883,154	)								(1,883,154	)
Currency translation adjustments													16,982			16,982
After-tax net unrealized gains related to derivatives accounted for as hedges (see Note 11)													69,186			69,186
After-tax net unrealized gains on derivative transactions reclassified into earnings (see Note 11)													(11,921	)		(11,921	)
Unrealized gain-marketable securities													(29	)		(29	)

Comprehensive income for the period																(1,808,936	)
Dividends declared:
	Cumulative preferred stock of Xcel Energy						(3,180	)								(3,180	)
	Common stock						(362,601	)								(362,601	)
Issuances of common stock — net			67,706		510,195											577,901
Acquisition of NRG minority common shares			64,412		555,222								28,150			647,784
Other							163						14			177
Repayment of ESOP loan ^(a)										1,884						1,884

Balance at Sept. 30, 2002		$	996,621	$	4,035,006	$	309,631		$	(16,680	)	$	(77,072	)	$	5,247,506

(a)

Did not affect cash flows

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

In the opinion of management, the accompanying, unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) as of Sept. 30, 2002, and Dec. 31, 2001, the results of its operations and stockholders’ equity for the three months and nine months ended Sept. 30, 2002 and 2001, and its cash flows for the nine months ended Sept. 30, 2002 and 2001. Due to the seasonality of Xcel Energy’s electric and gas sales and variability of nonregulated operations, quarterly results are not necessarily an appropriate base from which to project annual results.

The accounting policies followed by Xcel Energy are set forth in Note 1 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2001 and its Current Report on Form 8-K filed Sept. 16, 2002. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K and Form 8-K.

Certain items in the 2001 income statement and balance sheet have been reclassified to conform to the 2002 presentation. These reclassifications had no effect on stockholders’ equity, net income or earnings per share as previously reported.

1. Accounting Policies and Changes

Intangible Assets — During the first quarter of 2002, Xcel Energy adopted Statement of Financial Accounting Standard (SFAS) No. 142- “Goodwill and Other Intangible Assets”, which requires new accounting for intangible assets, including 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 $40 million at Sept. 30, 2002, which will not be amortized, consisting of project-related goodwill at NRG Energy, Inc. (NRG) and Utility Engineering. At June 30, 2002, Xcel Energy had initially recorded $62 million of goodwill related to the acquisition of NRG’s minority shares (see Note 5), which was subsequently reallocated to fixed assets related to projects where the fair value of the fixed assets was higher than the carrying value as of June 2002 and to prepaid pension assets. During the first nine months of 2002, Xcel Energy performed impairment tests of its intangible assets. Tests completed to date have concluded that no write-down of these intangible assets is necessary.

With respect to those intangible assets that will continue to be amortized, aggregate amortization expense recognized in the three and nine months ended Sept. 30, 2002, was $2.0 million and $3.9 million, respectively. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $3.5 million. Intangible assets consisted of the following:


		Sept. 30, 2002				Dec. 31, 2001

		Gross Carrying		Accumulated		Gross Carrying		Accumulated
Class of Intangible Asset		Amount		Amortization		Amount		Amortization

		(Millions of dollars)
Not Amortized:
	Goodwill	$	47.9	$	7.7	$	74.7	$	10.8
Amortized:
	Service contracts	$	73.2	$	17.1	$	90.9	$	19.8
	Trademarks	$	5.1	$	0.5	$	5.0	$	0.4
	Other (primarily franchises)	$	1.8	$	0.5	$	1.9	$	0.3

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

The following table summarizes the pro forma impact of implementing SFAS No. 142 at Jan. 1, 2001, 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.


	3 Months Ended					9 Months Ended

	Sept. 30, 2002			Sept. 30, 2001		Sept. 30, 2002			Sept. 30, 2001

	(Millions of dollars)
Reported net income (loss)	$	(2,074.0	)	$	272.9	$	(1,883.2	)	$	650.1
Add back: Goodwill amortization (after tax)		—			0.9		—			2.4

Adjusted net income (loss)	$	(2,074.0	)	$	273.8	$	(1,883.2	)	$	652.5

Diluted earnings (loss) per share	$	(5.22	)	$	0.79	$	(5.01	)	$	1.89

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.

Trading Operations — In June 2002, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (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 income, 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 $1.0 billion and $679 million for the third quarter of 2002 and 2001, respectively. Such reclassifications for the nine months ended Sept. 30, 2002 and 2001 were $2.8 billion and $2.4 billion, respectively. This reclassification had no impact on trading margins 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 — “Accounting for Derivative Instruments and Hedging Activities” 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 has not yet evaluated the effect of adopting this decision when required in 2003.

Diluted Earnings Per Share — Diluted earnings per share is based on the weighted average common stock and common equivalent shares outstanding each period. However, no common equivalent shares shall be included in the computation of any diluted per-share amounts when a loss from continuing operations exists due to their antidilutive effect. Therefore, common equivalent shares of approximately 5.8 million and 2.0 million were excluded from the diluted earnings per share computations for the three and nine months ended Sept. 30, 2002, respectively.

2. Special Charges and Asset Impairments

Special charges included in Operating Expenses include the following:


		3 Months Ended				9 Months Ended

		Sept. 30, 2002		Sept. 30, 2001		Sept. 30, 2002		Sept. 30, 2001

		(Millions of dollars, except EPS)
NRG Asset Impairments		$	2,891	$	—	$	2,891	$	—
NRG Restructuring Costs			18		—		38		—
NEO Charges (NRG)			—		—		36		—
Regulatory Recovery Adjustment (SPS)			—		—		5		—
Restaffing (Utility and Service Companies)			—		—		9		—
Postemployment Benefits (PSCo)			—		—		—		23

	Total Special Charges	$	2,909	$	—	$	2,979	$	23

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

NRG Asset Impairments — As discussed further in Note 7, during the third quarter of 2002, NRG experienced credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity. These events resulted in impairment reviews of a number of NRG assets. NRG completed an analysis as of Sept. 30, 2002 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 were significantly affected by NRG’s credit rating downgrade at the end of July 2002. 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 the third quarter of 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 the third quarter of 2002 as follows:

Status

Pretax Charge

Fair Value Basis

(Millions of dollars)

Projects In Construction or Development

Nelson

Terminated

620

Similar asset prices

Pike

Terminated; in

bankruptcy

529

Similar asset prices

Bourbonnais

Terminated

270

Similar asset prices

Meriden

Terminated

180

Similar asset prices

Brazos Valley

Foreclosure in process

103

Projected cash flows

Kendall & Batesville

expansion and other

Terminated

147

Similar asset prices

Langage (UK)

Terminated

Estimated market price

Turbines & other costs

Equipment being sold

309

Similar asset prices

Total

2,202

Operating Projects

Killingholme (UK)

Foreclosure in process

478

Projected cash flows

Audrain

Operating at a loss

Projected cash flows

Hsin Yu (Taiwan)*

Funding discontinued;

operating at a loss

122

Projected cash flows

Other

Operating at a loss

Projected cash flows

Total

689

Total NRG Impairment Charges

2,891

* Excluding minority interest impact, which would reduce pretax cost by $21 million.

All of these impairment charges relate to assets considered held for use under SFAS 144. For fair values determined by similar asset prices, the fair value represents NRG’s current estimate of recoverability from expected marketing of project assets. 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 (using rates of 8-10 percent) 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.

The Loy Yang project is an equity method investment, not subject to SFAS No. 144 impairment provisions. In the second quarter of 2002, NRG began marketing this investment for sale with the condition that it would only sell the investment if it could recover its current carrying value. Since the Company has not received an offer to recover its carrying amount, NRG will continue to hold its investment as long as it has the capability to do so. However, if the Company had elected to sell this investment as of Sept. 30, 2002, it would be required under generally accepted accounting principles to recognize any foreign currency adjustments recorded as a component of accumulated other comprehensive income into income rather than as a component of equity. As of Sept. 30, 2002, foreign currency adjustments of $89 million were deferred in OCI that would be recognized as a loss if the Company had elected to sell this investment. Based on market appraisals received in the second and third quarters, it was determined in the third quarter of 2002 that there has been a decline in Loy Yang’s fair value that is considered by the Company to be other than temporary. Accordingly, an impairment charge of approximately $54 million has been recognized at Sept. 30, 2002.

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

Additional asset impairments may be recorded by NRG in periods subsequent to Sept. 30, 2002, given the changing business conditions and the resolution of the pending restructuring plan. Management is unable to determine the possible magnitude of any additional asset impairments.

NRG Severance and Restructuring — In the second quarter of 2002, NRG expensed a pretax charge of $20 million, or 4 cents per share, for expected severance and related benefits. Additional severance accruals of $6 million, or 1 cent per share, were made in the third quarter of 2002. Through Sept. 30, 2002, severance costs have been recognized for all employees who had been terminated as of that date. Similar charges are expected to be expensed in the future, as further actions are taken, but are not determinable at this time. Another $12 million, or 2 cents per share, of other NRG restructuring costs were recorded in the third quarter of 2002, including financial advisors, legal advisors and consultants. See Note 6 for further discussion of NRG restructuring activities and developments.

NRG Charges-NEO Project — During the second quarter of 2002, NRG expensed a pretax charge of $36 million, or 6 cents per share, related to its NEO Corporation landfill gas generation operations. The charge was related largely to asset impairments based on a revised project outlook. It also reflects the accrued impact of a dispute settlement with Fortistar, a partner with NEO in the landfill gas generation operations.

Regulatory Recovery Adjustment — In late 2001, Southwestern Public Service (SPS), a wholly owned subsidiary of Xcel Energy, filed an application requesting recovery of costs incurred to comply with transition to retail competition legislation in Texas and New Mexico. During the first quarter of 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, or approximately 1 cent per share.

2002 Restaffing — During the fourth quarter of 2001, Xcel Energy recorded an estimated liability for expected staff consolidation costs for an estimated 500 employees in several utility operating and corporate support areas of Xcel Energy. In the first quarter of 2002, the identification of affected employees was completed and additional pretax special charges of $9 million, or approximately 1 cent per share, were expensed for the final costs of the utility-related staff consolidations. All 564 of accrued staff terminations have occurred.

The following table summarizes the activity related to accrued special charges for restaffing in the first nine months of 2002.


		Dec. 31, 2001		Accrued					Sept. 30, 2002
		Liability		Special Charges		Payments			Liability

		(Millions of dollars)
Utility and corporate employee severance *		$	37	$	9	$	(31	)	$	15
NRG employee severance **			—		26		(5	)	$	21

	Total accrued special charges	$	37	$	35	$	(36	)	$	36

*		Reported on the balance sheet in other current liabilities.

**		$18.5 million reported on the balance sheet in other current liabilities and $2.5 million reported in benefit obligations and other.

Postemployment Benefits — Earnings for the second quarter of 2001 were reduced by 4 cents per share due to a Colorado Supreme Court decision that resulted in a 2001 pretax write-off of $23 million of regulatory assets related to deferred postemployment benefit costs at Public Service Company of Colorado (PSCo), a wholly owed utility subsidiary of Xcel Energy.

3. Discontinued Operations and Assets Held for Sale

In the second and third quarters of 2002, NRG applied the provisions of SFAS No. 144 — Accounting for the Impairment or Disposal of Long-Lived Assets, to certain of its assets, which were held for sale. 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 considered cash flow analyses, bids and offers, related to those businesses. As a result, NRG recorded an estimated losses of $86 million on disposal for assets held for sale. A portion of this amount is included as Income (loss) from discontinued operations for consolidated projects and the majority is reported as Estimated loss from disposal of equity investments for equity method projects in the accompanying Consolidated Statements of Income. In accordance with the provisions of SFAS No. 144, the assets classified as assets held for sale will not be depreciated commencing the beginning of the month in which they were classified as such.

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

Discontinued Operations — NRG

As of Sept. 30, 2002, four projects of NRG (Bulo Bulo, Csepel, Entrade and Crockett Cogeneration Project) that were consolidated on NRG’s financial statements had been classified as held for sale. The operating results and estimated losses on disposal for these projects have been separately classified and reported as discontinued operations in the accompanying financial statements.

Bulo Bulo — In June 2002, NRG began negotiations for the sale of its 60-percent interest in Companie Electrica Central Bulo Bulo S.A. (Bulo Bulo), a Bolivian corporation, to its 40 percent partner, Pan American Energy LLC. During the second quarter of 2002, NRG classified Bulo Bulo as held for sale and recognized an estimated disposal loss of approximately $9.7 million as discontinued operations. The transaction is expected to reach financial close in fourth quarter 2002.

Crockett Cogeneration Project — In September 2002, NRG announced that it had reached an agreement to sell its 57.7-percent interest in Crockett Cogeneration Project, a 240-megawatt, natural gas-fueled cogeneration plant near San Francisco, Calif., to an undisclosed buyer. Upon closing of the sale of Crockett, NRG expects to realize net cash proceeds of approximately $70 million and expects to reduce balance sheet debt and credit obligations by approximately $240 million. Crockett has been classified as held-for-sale and a loss of approximately $7 million has been reported in discontinued operations in the third quarter of 2002.

Hungarian and Czech Assets — In September 2002, NRG announced it had reached agreement to sell its Csepel power generating facilities, its 44.5-percent interest in ECKG power station and its interest in Entrade, an electricity trading business, to Atel, an independent energy group headquartered in Switzerland. NRG expects to realize net cash proceeds of approximately $200 million from the sale with closing anticipated in first quarter 2003. The transaction, which requires approval by competition authorities, is expected to close before year-end and is expected to result in a gain, net of transaction fees. This gain will not be recognized until closing occurs.

Located on Csepel Island in Budapest, Hungary, Csepel I is a 116-megawatt thermal plant, and Csepel II is a 389-megawatt gas turbine power generating station. ECKG, a 343-megawatt coal- and gas-fueled power station and a 173-megawatt thermal plant, is located in Kladno, Czech Republic. Based in Prague, Entrade markets and trades electricity in Central and Eastern Europe.


The following is a summary of the components of discontinued operations:
	3 Months Ended					9 Months Ended
	Sept. 30					Sept. 30

	2002			2001		2002			2001

	(Thousands of dollars)
Operating Revenues	$	121,976		$	103,100	$	373,080		$	280,203
Operating & Other Expenses		121,308			87,247		338,158			263,416
Estimated Loss on Disposal		(7,423	)		—		(17,097	)		—

Income (loss) before taxes		(6,755	)		15,853		17,825			16,787
Income tax expense		—			1,769		—			1,805

Net income (loss) from discontinued operations	$	(6,755	)	$	14,084	$	17,825		$	14,982

Other Assets Held for Sale — NRG

As of Sept. 30, 2002, five significant projects of NRG (Collinsville, ECKG, Energy Development Limited, SRW Cogeneration and Mt. Poso) that were reflected as equity investments on NRG’s financial statements had been classified as held for sale. In the accompanying financial statements, the operating results of these projects are classified in revenue as Equity earnings from investments in affiliates, and the estimated losses on disposal for these projects have been classified and reported as a component of Estimated loss from disposal of equity investments for equity method projects. For the nine months ended Sept. 30, 2002, NRG had recorded charges of $117.9 million to write-down the carrying value of equity investments due to losses expected from sales.

Energy Development Limited — On July 25, 2002, NRG announced it had agreed to the sale of its ownership interests in an Australian energy company, Energy Development Limited (EDL). EDL is engaged in the development and management of an international portfolio of projects with a particular focus on renewable and waste fuels. In October 2002, NRG received proceeds of $78.5 million (AUS), or approximately $43.9 million (USD), from the sale in exchange for its ownership interest in EDL with the closing of the transaction. During the second quarter of 2002, NRG recognized an estimated loss on the sale of approximately $14.3 million in the third quarter of 2002.

Collinsville Power Station — In August 2002, NRG announced it had entered into an agreement for the sale of its 50-percent interest in the 192-megawatt Collinsville Power Station in Australia to an existing partner, a subsidiary of Transfield Services Limited for $8.6 million (AUS), or approximately $4.8 million (USD). NRG recognized an estimated loss on the sale of approximately $4.1 million (USD) during the second quarter of 2002.

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

Sabine River — In September 2002, NRG agreed to transfer its indirect 50 percent interest in SRW Cogeneration LP (SRW), which owns a cogeneration facility in Orange County, Texas, to Conoco, in consideration for Conoco’s agreement to terminate or assume all of the obligations of NRG in relation to SRW including all of NRG’s obligations under the Tolling Agreement with SRW. The sale closed on Nov. 5, 2002 and resulted in a loss of approximately $49 million which was accrued in the third quarter of 2002.

Mount Poso — In September 2002, NRG agreed to sell its 39.5 percent indirect partnership interest in Mt. Poso Cogeneration Company, a California limited partnership (Mt. Poso), which owns a 49.5 megawatt coal-fired cogeneration power plant and thermally enhanced oil recovery factory in California, to Red Hawk Energy, LLC of $10 million less financial advisors fees of $200,000. This sale is expected to close in November 2002 and is expected to result in a loss to NRG of approximately $400,000, which was accrued in the third quarter of 2002.

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 Statement of Income.

4. Business Developments

NRG Divestitures and Project Terminations

Conectiv — In April 2002, NRG terminated its agreement with a subsidiary of Conectiv, pursuant to which NRG was to acquire 794 megawatts of generating capacity and other assets, including an additional 66 megawatts of the Conemaugh Generating Station and an additional 42 megawatts of the Keystone Generating Station. Canceling the acquisition will result in a $230 million reduction in NRG’s capital spending for 2002. No incremental costs were incurred by NRG related to the termination of this agreement.

FirstEnergy Assets — In 2001, NRG had signed purchase agreements to acquire or lease a portfolio of generating assets from FirstEnergy Corporation. Under the terms of the agreements, NRG had agreed to finance approximately $1.6 billion for four primarily coal-fueled generating stations.

On Aug. 8, 2002, FirstEnergy notified NRG that the agreements related to FirstEnergy generating assets had been cancelled. FirstEnergy cited the reason for canceling the agreements as an alleged anticipatory breach of certain obligations in the agreements by NRG. FirstEnergy also notified NRG that it is reserving the right to pursue legal action against NRG and Xcel Energy for damages, based on the alleged anticipatory breach. At this time, NRG cannot predict the effect on NRG of any legal action that might be brought. NRG continues to evaluate the implications of the cancellation and its potential exposure to FirstEnergy.

LSP Pike Energy, LLC — In August 2002, The Shaw Group (Shaw) and NRG tentatively entered into an agreement to transfer NRG’s interest in the assets in LSP Pike Energy, LLC (Pike) to Shaw. Pike is a 1,200-megawatt, combined-cycle gas turbine plant currently under construction in Mississippi, which is approximately one-third completed. The agreement was subject to approval by the NRG board of directors and lenders. Pike, NRG and the Pike Project lenders have not approved the agreement and are not expected to in the near term.

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

On Oct. 17, 2002, Shaw filed an involuntary petition for liquidation of Pike in the U.S. District Court for the Southern District of Mississippi under Chapter 7 of the U.S. Bankruptcy Code. Shaw also filed suit against Xcel Energy, NRG, certain NRG subsidiaries, Wayne Brunetti and Richard Kelly. The suit seeks recovery of approximately $130 million, as a result of what Shaw asserts are multiple breaches of contract and under various other liability theories, including that the corporate veils between Xcel Energy, NRG and Pike should be ignored. Defendants expect to challenge the allegations vigorously. The carrying value of NRG’s Pike assets has been reduced substantially as a result of the asset impairments reflected as Special Charges. See discussion in Note 2.

Discontinued Operations and Assets Held for Sale — See Note 3 for discussion of other NRG divestitures that are reported as discontinued operations or assets held for sale as of Sept. 30, 2002.

Other Developments

TRANSLink Transmission Company, LLC (TRANSLink) — In September 2001, Xcel Energy and several other electric utilities applied to the Federal Energy Regulatory Commission (FERC) to integrate operations of their electric transmission systems into a single system through the formation of TRANSLink, a for-profit, independent transmission-only company. The utilities will participate in TRANSLink through a combination of divestiture, leases and operating agreements. The applicants are: Alliant Energy’s Iowa company (Interstate Power and Light Co.), Corn Belt Power Cooperative, MidAmerican Energy Co., Nebraska Public Power District, Omaha Public Power District and Xcel Energy. The participants believe TRANSLink is the most cost-effective option available to manage transmission and to comply with regulations issued by the FERC in 1999, known as Order No. 2000, that require investor-owned electric utilities to transfer operational control of their transmission system to an independent regional transmission organization (RTO).

Under the proposal, TRANSLink will be responsible for planning, managing and operating both local and regional transmission assets. TRANSLink also will construct and own new transmission system additions. TRANSLink will collect revenue for the use of Xcel Energy’s transmission assets through a FERC-approved, regulated cost-of-service tariff and will collect its administrative costs through transmission rate surcharges. Transmission service pricing will continue to be regulated by the FERC, but construction and permitting approvals will continue to rest with regulators in the states served by TRANSLink. The participants also have entered into a memorandum of understanding with the Midwest Independent Transmission Operator, Inc. (MISO) in which they agree that TRANSLink will contract with the MISO for certain other required RTO functions and services. In May 2002, the partners formed TRANSLink Development Company, LLC., which is responsible for pursuing the actions necessary to complete the regulatory approval of TRANSLink Transmission Company, LLC.

In April 2002, the FERC gave conditional approval for the applicants to transfer ownership or operations of their transmission systems to TRANSLink and to form TRANSLink as an independent transmission company operating under the umbrella RTO organization of MISO. The FERC conditioned TRANSLink’s approval on the resubmission of its tariff as a separate rate schedule to be administered by the MISO. TRANSLink Development Company made this rate filing in October 2002. Eleven intervenors had requested that the FERC clarify or reconsider elements of the TRANSLink decision. On Nov. 1, 2002, the FERC issued its order supporting the approval of the formation of TRANSLink. The FERC also clarified several issues covered in its April 2002 order. Several state approvals also would be required to implement the proposal, as well as SEC approval. Subject to receipt of required regulatory approvals, TRANSLink is expected to begin operations in the third quarter of 2003.

Viking Gas Transmission Company — On Nov. 7, 2002, Xcel Energy reached an agreement to sell its wholly owned subsidiary, Viking Gas Transmission Company (Viking) and Viking’s share of Guardian Pipeline to Border Viking Company (Border) whose ultimate parent is Northern Border Partners L.P. Pursuant to the agreement, Border would purchase Viking and a one-third interest in Guardian Pipeline for approximately $152 million, including the assumption of outstanding debt. The purchase is expected to close in the first quarter of 2003, subject to receipt of all necessary approvals.

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

5. Acquisition of Minority NRG Common Shares

During the second quarter of 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 $650 million as of June 30, 2002. Due to the acquisition occurring near quarter-end, additional acquisition costs recorded in the third quarter of 2002 increased the purchase price as of Sept. 30, 2002, to $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 was initially completed during the third quarter and resulted in approximately $62 million of amounts preliminarily reported as goodwill which have subsequently been reallocated to fixed assets related to projects where the fair values were in excess of carrying values and to prepaid pension assets. The preliminary purchase price allocation is subject to change as the final purchase price allocation and asset valuation process is completed.

6. NRG Restructuring Plan

Since mid-August, 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 anticipates that NRG will function independent 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 the forecasted cash flow information included in the business plan. Management concluded that the forecasted free cash flow available to NRG after servicing project-level obligations will be insufficient to service recourse debt obligations. Based on this information in conjunction with Xcel Energy and its financial advisor, NRG prepared and submitted to its, and a number of its subsidiaries’ various lenders, bondholders and other creditor groups (collectively, “NRG’s Creditors”) a restructuring plan on Nov. 4, 2002. The restructuring plan is expected to serve as a basis for negotiations with NRG’s Creditors in a financially-restructured NRG and, among other things, proposes (i) holders of secured (project-level) debt would either (a) have their debt reinstated with agreed modifications or (b) receive the collateral securing such debt and a claim or claims to the extent such debt is under-secured; (ii) holders of unsecured debt, holders of secured recourse claims against NRG, and holders of other general unsecured claims against NRG would receive a pro rata share of (a) an aggregate of $500 million of junior secured debt of reorganized NRG and (b) 95% of the common equity of reorganized NRG; and (iii) holders of project-level general unsecured claims that are non-recourse to NRG would receive a pro rata share of the remaining 5% of the common equity of reorganized NRG.

The restructuring plan also includes a proposal addressing Xcel Energy’s continuing role and degree of ownership in NRG and obligations to NRG. Based on the advice of its financial advisor that NRG is likely insolvent and in return for a release of any and all claims against Xcel Energy, the plan proposes that, upon consummation of the restructuring, Xcel Energy would pay $300 million to NRG. The plan separately proposes that Xcel Energy surrender its equity ownership of NRG. The plan does not contemplate any sharing by Xcel Energy with NRG’s Creditors of any benefits Xcel Energy might receive in connection with the tax matters described below. There can be no assurance that the restructuring plan submitted by NRG will be accepted by NRG’s Creditors or that it will not be significantly revised as a result of ongoing negotiations. Furthermore, there can be no assurance that NRG’s Creditors ultimately will accept any consensual restructuring plan. Xcel Energy is unable to predict whether NRG will be able to implement any such restructuring plan, or whether, 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. On Nov. 6, 2002, lenders to NRG accelerated approximately $1.1. billion of NRG’s debt under a construction revolver financing facility, rendering the debt due and payable. Based on discussions with the lenders, it is NRG’s understanding that the administrative agent issued the acceleration notice to preserve certain rights under the construction revolver financing agreements.

Whether NRG does or does not reach 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. See “Potential NRG Bankruptcy” under Note 9.

Since the acquisition of 100 percent ownership of NRG in June 2002, Xcel Energy has been operating under the following assumptions related to income tax attributes assignable to NRG: (a) NRG is a going concern; (b) Xcel Energy retains a controlling interest in NRG; and (c) NRG will rejoin Xcel Energy’s consolidated group for federal income tax purposes effective June 2002 and will, again, become a party to Xcel Energy’s Tax Allocation Agreement. Under this Tax Allocation Agreement, subsidiaries are paid for taxable losses used by the consolidated group and likewise remit taxable income. To date, no formal election has been made by Xcel Energy to reconsolidate NRG for federal income tax purposes, and NRG has not become a signatory to the Tax Allocation Agreement. Consistent with the foregoing assumptions, Xcel Energy included NRG in its third quarter 2002 estimated income tax payment calculation as if it were included in Xcel Energy’s consolidated federal income tax group for 2002. In addition, Xcel Energy applied the Tax Allocation Agreement as if NRG were included in Xcel Energy’s Consolidated federal income tax group for 2002 and, therefore, made a cash payment of $24 million to NRG in September 2002 for tax benefits expected to be provided by NRG to the Xcel Energy consolidated tax group for the period from and after the acquisition of 100 percent ownership of NRG in June 2002. Based on changed circumstances subsequent to Sept. 30, 2002, it is likely, though not certain, that Xcel Energy will eventually decide not to consolidate NRG for income tax purposes for 2002 when Xcel Energy files its 2002 consolidated income tax returns in

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

2003. Xcel Energy’s decision in this regard will depend on a variety of factors, including the outcome of ongoing negotiations with NRG’s Creditors. If Xcel Energy does not consolidate NRG on its 2002 federal income tax return, such action may be contested by NRG’s Creditors.

7. NRG Liquidity & Related Credit Contingencies

NRG Credit Rating — In December 2001, Moody's placed NRG's long-term senior unsecured debt rating on review for downgrade. In response to this threat to NRG's investment grade rating, on Feb. 17, 2002, Xcel Energy announced a financial improvement plan for NRG, which included an initial step of acquiring 100 percent of NRG through a tender offer to exchange all of the outstanding shares of NRG common stock for Xcel Energy common shares. In addition, the plan included financial support to NRG from Xcel Energy; marketing certain NRG generating assets for possible sale; cancelling and deferring capital spending for NRG projects; and combining certain of NRG's functions with Xcel Energy's system and organization. On June 3, 2002, Xcel Energy completed its exchange offer for the 26 percent of NRG's shares that had been previously publicly held. Xcel Energy offered NRG shareholders 0.50 shares of Xcel Energy common stock for each outstanding share of NRG common stock (see Note 5). Throughout this period of time, NRG was in discussions with credit agencies and believed that its actions were sufficient to avoid a downgrade.

However, even with NRG's efforts to avoid a downgrade, unexpectedly on July 26, 2002, Standard & Poors' downgraded NRG's senior unsecured bonds below investment grade, and three days later Moody's Investors' Services 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 and the secured NRG South Central Generating LLC 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, depending on both the specific debt issue and the rating agency rating system. Credit ratings are not a recommendation to buy, sell or hold securities, and each rating should be evaluated independently of any other rating.

The current credit ratings of NRG have resulted in its inability to access the capital markets.

NRG Liquidity Issues — As a result of the credit rating agencies unexpectedly downgrading NRG’s credit rating below investment grade, NRG is required to post estimated collateral ranging from approximately $1.1 billion to $1.3 billion. NRG previously believed it could meet the collateral requirements that would result from such an occurrence with available cash, operating cash flows, equity contributions from Xcel Energy, proceeds from asset sales and the issuance of bonds into the capital markets or as a private placement.

NRG obtained an agreement with various lenders to extend, until Nov. 15, 2002, the deadline by which it must post this cash collateral. This deadline has passed and NRG has not posted the required collateral. The extension agreement called for NRG to submit a comprehensive restructuring plan to its lenders and bondholders by late October (see Note 6). The extension agreement did not waive other events of default, including failure to make principal and/or interest payments when due or failure to comply with financial covenants. Nor did the extension agreement waive the rights of the bank group or the bondholders to pursue any rights and remedies in respect of such other defaults.

On Nov. 6, 2002, lenders to NRG accelerated approximately $1.1 billion of NRG's debt under a construction revolver financing facility, rendering the debt immediately due and payable. This action terminated the collateral call extension letter (CCEL) in effect between NRG and its major lenders. The extension letter was previously scheduled to expire Nov. 15, 2002. Based on discussions with the construction revolver lenders it is NRG's understanding that the administrative agent, Credit Suisse First Boston, issued the acceleration notice to preserve certain rights under the construction revolver financing agreements. NRG believes that the administrative agent intends to forbear in the immediate exercise of any rights and remedies against NRG.

NRG has missed several scheduled payments of interest and principal on some of its bonds as discussed later and in Part II, Item 3. 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 and that would likely lead to a bankruptcy filing by NRG.

In addition, NRG South Central LLC, a wholly owned subsidiary of NRG, has not made approximately $47 million in combined principal and interest payments on 8.962 percent series A-1 senior secured bonds due 2016 and 9.479 percent series B-1 senior secured bonds due 2024. As discussed above, pending agreement on a restructuring plan, NRG does not expect to make any further payments of principal or interest on its debt.

As discussed in Note 6, NRG continues to work with its lenders on a comprehensive restructuring plan that would address the collateral requirements and its debt and other obligations. Absent an agreement on this restructuring plan, NRG will continue to be in default under its debt and other obligations because it does not have sufficient funds

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to meet the requirements and obligations. There can be no assurance that NRG will be able to effect a consensual restructuring or otherwise satisfactorily resolve these issues soon, or at all. It is unlikely that Xcel Energy ultimately will own any equity interest in a restructured NRG.

In addition to the collateral requirements and its debt payment obligations, NRG must continue to meet its ongoing operational and construction funding requirements. Since NRG’s downgrade, its cost of borrowing has increased and it has no access to the capital markets. As a consequence, NRG has developed an updated business plan and, in October 2002 and early November 2002, presented this plan along with a comprehensive restructuring plan to its lenders and bondholders (see Note 6). NRG believes that its current funding requirements under its already reduced construction program may be unsustainable given its inability to raise cash through 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 issues. NRG is unsure as to the resolution of all issues. NRG’s initial priorities have been obtaining waivers to delay its collateral calls and developing of a restructuring plan.

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As discussed earlier, NRG is not making any payments of principal and interest on its corporate level debt and neither NRG nor any subsidiary is making payment of principal or interest on publicly-held bonds and certain project-level credit facilities. 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 enforce their remedies, which would likely lead to NRG seeking relief under bankruptcy laws.

At the present time and based on conversations with various lenders, Xcel Energy management believes that the appropriate course of action is to seek a consensual restructuring of NRG with NRG Creditors. Following an agreement on the restructuring with NRG’s Creditors and as described in Note 6 above, 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, substantial doubt would exist as to NRG's ability to continue as a going concern and, the likelihood of NRG being subject to a protracted voluntary or involuntary bankruptcy proceeding is increased. Although there is a substantial likelihood that NRG will be the subject of a bankruptcy proceeding, 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.

NRG Debt Covenants and Restrictions

As a consequence of NRG’s credit rating downgrades, defaults under certain agreements, including collateral requirements, reduced liquidity and asset impairments (discussed in Note 2) that occurred during the third quarter of 2002, a portion of NRG’s long term debt obligations have been classified as a current liability on the accompanying balance sheets due to the lenders having the ability to call such debt, including $3.1 billion that is in default. As of Sept. 30, 2002, approximately $6.7 billion of NRG’s long term debt has been reclassified to current from long term.

Short-term Credit Facility Covenants — In May 2001, NRG’s wholly-owned subsidiary, NRG Finance Company I LLC, entered into a $2-billion revolving credit facility. The facility terminates on May 8, 2006, and is non-recourse to NRG other than its obligation to contribute equity at certain times in respect of projects and turbines financed under the facility. As of Sept. 30, 2002, the aggregate amount outstanding under this facility was $1.1 billion, and NRG estimates the obligation to contribute equity to be approximately $819 million. Interest and fees due on Sept. 30, 2002 were not paid and supporting construction and other contracts associated with Pike and Nelson were violated by NRG in September 2002 and October 2002, respectively. Supporting construction and other contracts associated with NRG’s Pike and Nelson projects were violated by NRG in September and October 2002, respectively. Thus this facility is currently in default. See additional discussion regarding this facility and other short-term credit facility defaults in Note 10.

NRG Defaults Upon Senior Securities — On Sept. 16, 2002, NRG failed to make a $14.4-million interest payment due on $350 million of 8.25 percent senior unsecured notes due in 2010 and a $10.9-million interest payment due on a $250 million bond issued by NRG Pass-Thru Trust I trust, which is a wholly owned special financing entity that is effectively a senior unsecured obligation of NRG with an interest rate of 8.70 percent that matures in 2005. The 30-day grace period to make payment ended Oct. 16, 2002, and NRG did not make the required payments. As a result, NRG is in default on these bonds.

On Oct. 1, 2002, NRG failed to make a $13.6-million interest payment due on $350 million of 7.75 percent senior unsecured notes due in 2011 and a $21.6-million interest payment due on $500 million of 8.625 percent senior unsecured notes due in 2031. The 30-day grace period to make payment ended Oct. 31, 2002, and NRG did not make the required payments. As a result, NRG is in default on these bonds.

On Nov. 1, 2002 NRG failed to make a $9.6 million interest payment due on $240 million of 8.00 percent senior unsecured notes due in 2013. The 30-day grace period to make payment ends Dec. 1, 2002 and if NRG does not make the required payments, NRG will be in default on these bonds.

In addition, if certain creditors exercise rights of acceleration against $20 million or $50 million of NRG senior indebtedness, depending on the governing indenture, cross-default provisions place the following NRG senior unsecured debt in default: $300 million of 7.50 percent senior due 2009 (with a $11.3 million interest payment due on Dec. 1, 2002); $250 million of 7.50 percent senior notes due 2007 (with a $9.4 million interest payment due on Dec. 15, 2002); $340 million of 6.75 percent senior notes due 2006 (with a $11.5 million interest payment due on January 15, 2003); $125 million of a 7.625 percent due 2006 (with an interest payment of $4.8 million due Feb. 1, 2003).

On March 13, 2001, NRG completed the sale of 11.5 million equity units (NRZ) 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 Xcel Energy common stock no later than May 18, 2004. On Oct. 29, 2002, NRG announced it would not make the Nov. 16, 2002 quarterly interest payment on the NRG 6.5 percent senior unsecured debentures due in 2006, which trade with the associated purchase contracts as NRG corporate units (NRZ). The 30-day grace period to make payment ends Dec. 16, 2002, and if NRG does not make payment to the NRZ holders, this issue will be in default. In the event of an NRG bankruptcy, the obligation to purchase shares of Xcel Energy terminates.

Project Debt Service — Substantially all of NRG’s operations are conducted by project subsidiaries and project affiliates. 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 Sept. 30, 2002, seven of NRG’s subsidiaries and project affiliates are restricted from making cash payments to NRG: Loy Yang, Killingholme, Energy Center Kladno, LSP

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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. Additionally, Crockett Cogeneration is limited in its ability to make distributions to NRG and its other partners. 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, Crockett Cogeneration and Batesville do not create an event of default and will not allow the lenders to accelerate the project financings, thus these financing are not currently in default.

Many of the debt agreements of NRG's subsidiaries and project affiliates require the funding of debt service reserve accounts. Prior to the NRG downgrades, certain debt service reserve accounts funding requirements were satisfied by provision of a guarantee from NRG. Following the downgrade, those guarantees no longer qualified as acceptable credit support and the accounts were required to be funded with cash by NRG. The accounts were not funded with cash from NRG, and, after allowing for applicable cure periods, events of default were triggered under such project financings that allow the lenders to accelerate the project debt. NRG South Central Generating, NRG McClain, NRG MidAtlantic, Flinders, NRG Northeast Generating and Enfield are precluded from making payments to NRG due to unfunded debt service reserve accounts. NRG expects that the Killingholme and Brazos Valley projects will be foreclosed upon by the lenders.

Other Covenants and Compliance — The bankruptcy of Pacific Gas & Electric (PG&E) creates the potential for a covenant default that would result in the acceleration of the debt at Crockett if not resolved with the lenders. Management has engaged in active discussions with the lenders of Crockett since PG&E filed for bankruptcy in April 2001; additionally, Crockett is being paid each month by PG&E since the bankruptcy filing. PG&E and the Bankruptcy Court have affirmed the long-term power purchase agreement and PG&E is paying down the outstanding receivable over a 12-month period ending Dec. 1, 2002. Thus, NRG believes that an acceleration of the Crockett debt is unlikely. However, as of Dec. 31, 2001, NRG has reflected the entire balance of the Crockett debt as a current obligation in the amount of $234.5 million. As of Sept. 30, 2002, the outstanding balance of the Crockett debt has been reclassified as a current liability held for sale due to the pending sale of NRG’s interest in the project. For additional information regarding the pending sale of NRG’s interest in Crockett Cogeneration, see Note 3.

In May 2002, NRG’s indirect wholly owned subsidiary, LSP-Kendall Energy, LLC received a notice of default from Societe Generale, the administrative agent under LSP-Kendall’s Credit and Reimbursement Agreement dated Nov. 12, 1999. The notice asserted that an event of default had occurred under the Credit and Reimbursement Agreement as a result of liens filed against the Kendall project by various subcontractors. In consideration of the borrower’s implementation of a plan to remove the liens, and NRG’s indemnification pursuant to an Indemnity Agreement dated June 28, 2002, of the lenders to the Kendall project from any claims or damages relating to these liens or any dispute or action involving the project’s EPC contractor, the administrative agent, with the consent of the required lenders under the Credit and Reimbursement Agreement, withdrew the notice of default and conditionally waived any default or event of default described therein. Discussions with the administrative agent regarding the liens continue.

In June 2002, NRG Peaker Finance Company LLC (NRG Peaker), an indirect wholly owned subsidiary of NRG Energy, completed the issuance of $325 million of Series A Floating Rate Senior Secured Bonds due 2019. The bonds bear interest at a floating rate based on the 30-day London Interbank Offered Rate. 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 guaranties 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 guaranty 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. This financing contains a cross-default provision related to the failure by NRG to make payment of principal, interest or other amounts due on debt for borrowed money in excess of $50 million of payment defaults by NRG. This covenant was violated in October 2002. In addition, liens were placed against the Bayou Cove facility resulting in an additional default. As a result of these issues, this facility is in default.

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On Sept. 17, 2002, NRG-McClain LLC, an indirect wholly owned subsidiary of NRG, 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 under the Energy Management Services Agreement.

Brazos Valley Energy, LP, an indirect wholly owned subsidiary of NRG, is party to a credit facility that provides for borrowings of base rate loans and Eurocurrency loans and is secured by mortgages and security agreements in respect of the assets of the projects financed under the facility and pledges of the equity interests in the subsidiaries or affiliates of the borrower that own such projects.

On Sept. 30, 2002, Brazos Valley failed to make approximately $1.2 million in interest payments on the facility. Brazos Valley had five days to make interest payments to the lenders to avoid an event of default on the facility. The five-day grace period to make payment expired and Brazos Valley did not make the required payments. In addition, NRG has suspended equity contributions to the project. As a result, Brazos Valley is in default on this loan.

On Oct. 30, 2002 NRG failed to make $3.1 million in payment under certain Non-Operating Interest Acquisition agreements. As a result, NEO Landfill Gas, Inc., an indirect wholly owned subsidiary of NRG, failed to make approximately $1.4 million in payments under the Amended and Restated Construction, Acquisition and Term Loan Agreement, dated July 6, 1998. Also, the subsidiaries of NEO Landfill Gas, Inc. failed to make approximately $2 million in payments pursuant to various Site Development Operations and Coordination Agreements. NRG received an extension until Nov. 19, 2002 to make payment under such agreements. If NRG does not perform certain requirements during the extension period, NRG will be in default under the Non-Operating Interest Acquisition Agreements, and NEO Landfill Gas, Inc. will be in default under the Amended and Restated Construction, Acquisition and Term Loan Agreement, dated July 6, 1998, and the Site Development and Operations Coordination Agreements.

Electric Wholesale Generator (EWG) Approval — In April 2002, NRG discovered that filings with the FERC to exempt NRG’s Big Cajun Peaking facility in Louisiana from regulation by the SEC under the Public Utility Holding Company Act (PUHCA), and to sell power from the facility at market-based rates, had not been made. NRG has since discussed the situation with the FERC and the SEC and made those filings. EWG status was granted by the FERC, effective April 17, 2002. Although NRG does not expect any material legal or regulatory action to be taken by those agencies, the failure to have made these filings could be viewed as an event of default under certain of NRG’s debt facilities, including the $2 billion construction and acquisition revolving credit facility and the $1 billion unsecured corporate revolving line of credit. Accordingly, NRG sought and has received from its construction and acquisition revolving credit facility lenders a waiver of any event of default occurring as a result of Big Cajun Peaking Power’s failure to file for exemption from regulation under PUCHA, and has sought and received from its corporate revolver lenders an amendment to its corporate revolving line of credit to provide that such failure to obtain or maintain exemption from regulation under PUHCA will not cause an event of default under that facility. While the construction and acquisition revolver waiver and the corporate revolver amendment were being discussed and finalized with its lenders, NRG did not borrow under either of these credit facilities. The waiver under the construction and acquisition facility continues indefinitely unless a default arising out of any possible PUHCA violation relating to Big Cajun’s temporary failure to make these filings occurs. No fines or refunds have been asserted against NRG or any of its subsidiaries or affiliates by the FERC as a result of these missed filings.

Xcel Energy Impacts

Xcel Energy does not believe that the ultimate resolutions of NRG’s going concern uncertainty will 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 operations and current 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 has access to additional debt and equity financing that is not conditioned upon the outcome of NRG’s financial restructuring plan.

8. Rates and Regulation

Colorado

Merger Agreements — Under the Stipulation and Agreement approved by the Colorado Public Utilities Commission (CPUC) in connection with the Xcel Energy merger, PSCo agreed to 1) file a combined electric, gas and steam rate case in 2002 with new rates effective in January 2003, 2) extend its electric incentive cost adjustment (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 the 2001 actual costs, 3) continue the Performance Based Regulatory Plan and the Quality of Service Plan through 2006 with an electric department earnings cap of 10.5 percent return on equity for 2002, 4) reduce electric rates annually by $11 million for the period August 2000 to July 2002 and 5) cap merger costs associated with electric operations at $30 million and amortize such costs through 2002.

Incentive Cost Adjustment — In early 2002, PSCo filed to increase rates under the ICA to recover the undercollection of electric supply costs through the period ended Dec. 31, 2001 (approximately $14.5 million, which went into effect on June 1, 2002) and to increase the ICA base rate for the recovery of 2002 costs which are projected to be substantially

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higher than the $12.78 per megawatt hour currently being recovered. PSCo’s actual ICA base costs for 2001 were approximately $19 per megawatt hour. PSCo proposed to increase the ICA base in 2002 to avoid the significant deferral of costs and a large rate increase in 2003, although the Stipulation and Agreement provided for a rate recovery period of April 1, 2003, to March 31, 2004.

On May 10, 2002, the CPUC approved a Settlement Agreement between PSCo and other parties to increase the ICA base rate to $14.88 per megawatt hour, providing for recovery of the deferred 2001 costs and the projected higher 2002 costs over a 34-month period from June 1, 2002, to March 31, 2005. The prudency review and approval of actual costs incurred and recoverable under the ICA for 2001 and 2002 will be conducted in future rate proceedings by the CPUC. PSCo is currently projecting its costs for 2002 to be approximately $50 million to $60 million less than the ICA base allowed using the 2001 test year, resulting in an equal sharing of the difference between retail customers and PSCo. The mechanism for recovering fuel and energy costs for 2003 and later will be addressed in the pending 2002 rate case (discussed below).

General Rate Case — In May 2002, PSCo filed a combined general rate case with the CPUC to address increased costs for providing energy to Colorado customers. The net impact of the filings would increase electric revenue by approximately $220 million annually. This is based on $127 million for fuel and purchased power (including amounts deferred under the ICA) and $93 million for cost of electric service. In addition, PSCo also requested a decrease in natural gas revenue by approximately $13 million to reflect lower wholesale gas costs. PSCo also requested that its authorized rate of return on equity be set at 12 percent for electricity and 12.25 percent for natural gas.

The current schedule for the rate case, as approved by the CPUC, is as follows:

• November 2002 — intervenor testimony;

• January 2003 — company rebuttal testimony;

• February/March 2003 — hearings; and

• April/May 2003 — rates effective.

Gas Cost Prudence Review — In May 2002, the staff of the CPUC filed testimony in PSCo’s gas cost prudence review case, recommending $6.1 million in disallowances of gas costs for the July 2000 through June 2001 gas purchase year. Hearings were held in July 2002. A decision is expected in late 2002.

Texas

Transition to Competition Cost Recovery Application — In December 2001, SPS filed an application with the Public Utility Commission of Texas (PUCT) to recover $20.3 million in costs related to transition to retail competition from the Texas retail customers. These costs were incurred to position SPS for retail competition, which was eventually delayed for SPS. The filing was amended in March 2002 to reduce the request to $13 million to reflect the PUCT approval of SPS using 1999 over-earnings to offset the claims for reimbursement of transition to competition costs. In April 2002, a unanimous settlement agreement was reached. Final approval by the PUCT was received in May 2002. The stipulation provides for the recovery of $5.9 million through an incremental cost recovery rider and the capitalization of $1.9 million for metering equipment. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million in the first quarter of 2002. Recovery of the $5.9 million began in July 2002.

Fuel Clause Adjustment Mechanisms — The PUCT’s regulations require periodic examination of SPS’ fuel and purchased power costs, the efficiency of the use of such fuel and purchase power, fuel acquisition and management policies and purchase power commitments. SPS is required to file an application for the PUCT to retrospectively review, at least every three years, the operations of a utility’s electricity generation and fuel management activities.

In June 2002, SPS filed its fuel reconciliation to review costs recorded for calendar years 2000 and 2001 in the amount of $608 million. A pre-hearing conference was held in October 2002 and discovery in this case is in process. Hearings are scheduled for March 2003.

Minnesota

Metro Emissions Reduction Program — In July 2002, NSP-Minnesota filed for approval by the Minnesota Public Utilities Commission (MPUC) a proposal to invest in existing NSP-Minnesota generation facilities to reduce emissions under the terms of legislation adopted by the 2001 Minnesota Legislature. The proposal includes the installation of state-of-the-art pollution control equipment at the A.S. King plant and conversion from coal to natural gas at the High

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Bridge and Riverside plants. Under the proposal, major construction would start in 2005 and be completed in 2009. Under the terms of the statute, the filing concurrently seeks approval of a rate recovery mechanism for the costs of the proposal, estimated to be a total of $1.1 billion. The rate recovery would be through an annual automatic adjustment mechanism authorized by 2001 legislation, outside a general rate case, and is proposed to be effective at the expiration of the NSP-Minnesota merger rate freeze, which extends through 2005 unless certain exemptions are triggered. The rate recovery proposed by NSP-Minnesota would allow recovery of financing costs of capital expenditures prior to the in-service date of each plant. The proposal is pending comments by interested parties. Other regulatory approvals, such as environmental permitting, are needed before the proposal can be implemented.

Renewable Cost Recovery Tariff — In April 2002, NSP-Minnesota filed for MPUC authorization to recover in retail rates the costs of electric transmission facilities constructed to provide transmission service for renewable energy. The rate recovery would be through an automatic adjustment mechanism authorized by 2001 legislation, outside a general rate case, and is proposed to be effective Jan. 1, 2003. In July 2002, the Minnesota Department of Commerce filed comments supporting approval of the tariff mechanism, subject to certain modifications that are generally acceptable to Xcel Energy.

Minnesota Financial and Service Quality Investigation — On Aug. 8, 2002, the MPUC asked for additional information related to the impact of NRG’s financial circumstances on NSP-Minnesota. Subsequent to that date, several newspaper articles alleged concerns about the reporting of service quality data and NSP-Minnesota’s overall maintenance practices. In an order dated Oct. 22, 2002, the MPUC opened an investigation into the accuracy of NSP-Minnesota’s reliability records and to allow for further review of its maintenance and other service quality measures. In addition, the order requires a number of reporting requirements regarding financial information and work with interested parties on various issues to ensure NSP-Minnesota’s commitments are fulfilled. In addition, the order imposes restrictions on NSP-Minnesota's ability to seek rate increases, encumber utility property, provide intercompany loans and calculate cost of capital. The Minnesota Department of Commerce and Office of Attorney General also have begun their own investigation. There is no scheduled date for completion.

Federal Energy Regulatory Commission

Standard Market Design Rulemaking — In July 2002, the FERC issued a Notice of Proposed Rulemaking on Standard Market Design rulemaking for regulated utilities. If implemented as proposed, the Rulemaking will substantially change how wholesale markets operate throughout the United States. The proposed rulemaking expands the FERC’s intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The rule contemplates that all wholesale and retail customers will be on a single network transmission service tariff. The rule also contemplates the implementation of a bid-based system for buying and selling energy in wholesale markets. RTOs or Independent Transmission Providers will administer the market. RTOs will also be responsible for creating regional plans that identify opportunities to construct new transmission, generation or demand side programs to reduce transmission constraints and meet regional energy requirements. Finally, the Rule envisions the development of Regional Market Monitors responsible for ensuring that individual participants do not exercise unlawful market power. Comments to the rules are due in the fourth quarter of 2002 and first quarter of 2003. The FERC recently extended the comment period but anticipates that the final rules will be in place in 2003 and the contemplated market changes will take place in 2003 and 2004.

Standards of Conduct Rulemaking — In October 2001, the FERC issued a Notice of Proposed Rulemaking proposing to adopt new standards of conduct rules applicable to all jurisdictional electric and natural gas transmission providers. The proposed rules would replace the current rules governing the electric transmission and wholesale electric functions of the Xcel Energy utility subsidiaries and NRG, respectively; and the rules governing the natural gas transportation and wholesale gas supply functions of Viking Gas, e prime and the Xcel Energy utility subsidiaries, respectively. The proposed rules would expand the definition of “affiliate” and further limit communications between transmission functions and supply functions, and could materially increase operating costs of Xcel Energy. In April 2002, the FERC staff issued a reaction paper, generally rejecting the comments of parties opposed to the proposed rules. Though final rules were expected by year-end 2002, they may be delayed while the FERC pursues development of its Standard Market Design Rulemaking.

FERC Investigation — On May 8, 2002, the FERC ordered all sellers of wholesale electricity and/or ancillary services to the California Independent System Operator or Power Exchange, including Xcel Energy and NRG, to respond to data requests, including requests for admissions with respect to certain trading strategies in which the companies may have engaged. The investigation is in response to memoranda prepared by Enron Corporation that detail certain trading strategies engaged in 2000 and 2001, which may have violated market rules. On May 22, 2002, Xcel Energy reported to the FERC that it had not engaged directly in any of the trading strategies identified in the May 8th inquiry. On May 22, 2002, NRG responded that it had not engaged in any trading activities outlined in the FERC request.

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However, Xcel Energy also reported that at times during 2000 and 2001, its regulated operations did sell energy to another energy company that may then have re-sold the electricity for delivery into California as part of an overstated electricity load in schedules submitted to the California Independent System Operator. During that period, the regulated operations of Xcel Energy made sales to the other electricity provider of approximately 8,000 megawatt-hours in the California intra-day market, which resulted in revenues to Xcel Energy of approximately $1.5 million. Xcel Energy cannot determine from its records what part of such sales were associated with overschedules.

To supplement the May 8th request, on May 21, 2002, the FERC ordered all sellers of wholesale electricity and/or ancillary services in the United States portion of the Western Systems Coordinating Council during 2000 and 2001 to report whether they had engaged in activities referred to as “wash,” “round trip” or “sell/buyback” trading. On May 31, 2002, Xcel Energy reported to the FERC that it had not engaged in so-called round trip electricity trading identified in the May 21st inquiry.

On May 13, 2002, Xcel Energy reported that PSCo had engaged in a group of transactions in 1999 and 2000 with the trading arm of Reliant Resources in which PSCo bought a quantity of power from Reliant and simultaneously sold the same quantity back to Reliant. For doing this, PSCo normally received a small profit. PSCo made a total pretax profit of approximately $110,000 on these transactions. Also, PSCo engaged in one trade with Reliant in which PSCo simultaneously bought and sold power at the same price without realizing any profit. The purpose of this nonprofit transaction was in consideration of future for-profit transactions. PSCo engaged in these transactions with Reliant for the proper commercial objective of making a profit. It did not enter into these transactions to inflate volumes or revenues.

In addition, the FERC is assessing whether to set for hearing the justness and reasonableness of rates charged in the Pacific Northwest from Dec. 25, 2000, through June 20, 2001. The FERC directed that an administrative law judge hold a hearing and make a preliminary assessment as to whether it should undertake such an investigation. On Sept. 25, 2001, an administrative law judge concluded that no further proceedings should be held. Various parties have sought rehearing of that order and have requested that the record be reopened in light of the disclosure of the Enron trading strategies. The proceeding is pending before the FERC.

FERC Transmission Inquiry — The FERC has begun a formal, non-public inquiry relating to the treatment by public utility companies of affiliates in generator interconnection and other transmission matters. In connection with the inquiry, the FERC has asked Xcel Energy for certain information and documents. Xcel Energy is complying with the request.

SPS Commitment and Dispatch Agreement — Golden Spread Electric Power Cooperative, Inc. (Golden Spread) and SPS are parties to a commitment and dispatch agreement pursuant to which SPS commits and dispatches the combined resources of both entities to meet their combined load requirements. Under this agreement, SPS purchases a significant amount of energy from Golden Spread at rates designed to share the savings between both parties. Golden Spread has filed a complaint at the FERC contending that SPS has underpaid it for the power it has supplied under the agreement by not providing it with an appropriate share of the savings that SPS has achieved. SPS in turn has filed a complaint at the FERC contending that Golden Spread has improperly inflated various cost components of the rate calculation. FERC has set both complaints for investigation and hearing, but has deferred the hearing pending settlement proceedings. The matter is now before a settlement judge. Even if SPS is required to pay more to Golden Spread for power purchased under this agreement, it believes that the amounts will likely be recoverable from customers under applicable fuel clauses.

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

Securities and Exchange Commission/Commodity Futures Trading Commission

Temporary Modification of PUHCA Equity Ratio Limit — In accordance with an order from the SEC granting Xcel Energy authority to finance, Xcel Energy cannot currently issue any securities or guarantees if its common equity ratio is below 30 percent.

On Aug. 2, 2002, Xcel Energy filed a proposal with the SEC seeking authorization to engage in financing transactions at a time when Xcel Energy’s ratio of common equity to total capitalization is less than 30 percent. The proposal provided that the common equity of Xcel Energy, as reflected on its most recent Form 10-K, or Form 10-Q and as adjusted to reflect subsequent events that affect capitalization, be at least 24 percent of total capitalization. In addition, Xcel Energy proposed not to engage in any financing transactions after June 30, 2003, unless at such time Xcel Energy has an equity ratio of at least 30 percent. Xcel Energy expects that any reduction of its common equity ratio below 30 percent would be temporary pending resolution of the NRG restructuring.

On Nov. 7, 2002, the SEC issued an order authorizing Xcel Energy to engage in certain financing transactions through Mar. 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. At Sept. 30, 2002, and as adjusted for pending subsequent items that affect capitalization, Xcel Energy’s common equity ratio was at least 24 percent. 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 stock (less any amounts issued as part of the refinancing of the $400-million 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. Xcel Energy also has the authority, under PUHCA, to issue approximately $100 million of debt securities with maturities of not more than nine months. In the event NRG were to seek protection under bankruptcy laws and Xcel Energy ceased to have control over NRG, NRG would cease to 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.

SEC and CFTC Subpoenas — Xcel Energy has received a subpoena from the SEC for documents concerning “round trip trades,” as defined in the SEC subpoena, in electricity and natural gas with Reliant Resources, Inc. for the period Jan. 1, 1999, to the present. The SEC subpoena is issued pursuant to a formal order of private investigation that does not name Xcel Energy. Based upon accounts in the public press, management believes that similar subpoenas in the same investigations have been served on other industry participants. Xcel Energy and PSCo are cooperating with the regulators and taking steps to assure satisfactory compliance with the subpoenas.

Xcel Energy and PSCo have also received subpoenas from the Commodity Futures Trading Commission for documents and other information concerning these so-called “round trip trades” and other trading in electricity and natural gas for the period Jan. 1, 1999, to the present involving Xcel Energy or any of its subsidiaries.

9. Commitments and Contingent Liabilities

Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them.

Xcel Energy and its subsidiaries have been or are currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, Xcel Energy is pursuing or intends to pursue insurance claims and believes it will recover some portion of these costs through such claims. Additionally, where applicable, Xcel Energy is pursuing, or intends to pursue, recovery from other potentially responsible parties and through the rate regulatory process. To the extent any costs are not recovered through the options listed above, Xcel Energy would be required to recognize an expense for such unrecoverable amounts.

Note 7 to the Financial Statements describes the current status of credit contingencies related to NRG and related financial impacts. The circumstances set forth in Notes 15 and 16 to Xcel Energy’s financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2001, appropriately represent, in all material respects, the current status of other commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident, and are incorporated herein by reference. The following are unresolved contingencies discussed in the 2001 Annual Report on Form 10-K that are material to Xcel Energy’s financial position as of Sept. 30, 2002:

• California Power Market — Collectibility of NRG receivables;

• Tax Matters — Tax deductibility of corporate-owned life insurance loan interest and

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Commitments

Capital Commitments — Xcel Energy has received and revised its capital expenditure forecast. The utility capital expenditure forecast is detailed in the following table.


	2002		2003		2004

	(Millions of dollars)
Total utility	$	960	$	925	$	1,030

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 affect 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. Xcel Energy currently is evaluating the circumstances under which it would make any further investment in NRG.

In September 2002 and in connection with NRG’s collateral extension agreement, Xcel Energy provided NRG with an acknowledgement letter pursuant to which Xcel Energy acknowledged and agreed that demand for a drawing of the $300 million had been made by NRG and its lenders, pursuant to the Support and Capital Subscription Agreement; and funds provided by Xcel Energy will be contributed as equity or as subordinated loans. As a part of the agreement, NRG and its lenders agreed not to enforce the terms of the Support and Capital Subscription Agreement, in exchange for which Xcel Energy agreed not to make any dividends or repurchase shares of its capital stock during the term of the collateral extension agreement, expiring on Nov. 15, 2002, if it would negatively affect its ability to perform under the Support and Capital Subscription Agreement. See further discussion at Note 6.

Environmental Contingencies

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 United States 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. Xcel Energy disagrees with the assertions contained in the NOV and intends to vigorously defend its position.

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 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

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

requirements. In 2001, Xcel Energy responded to EPA’s initial information requests related to NSP-Minnesota plants in Minnesota. On May 22, 2002, EPA issued a follow-up information request to Xcel Energy seeking additional information regarding NSR compliance at its plants in Minnesota. Xcel Energy is in the process of responding to the follow-up request.

NRG Opacity Consent Order — NRG became part of an opacity consent order as a result of acquiring its Huntley, Dunkirk and Oswego plants from Niagara Mohawk. At the time of financial close on these assets, a consent order was being negotiated between Niagara Mohawk and the New York Department of Environmental Conservation (NYDEC). The order required Niagara Mohawk to pay a stipulated penalty for each opacity event at these facilities. On Jan. 14, 2002, the NYDEC issued NRG NOVs for opacity events, which had occurred since the time NRG assumed ownership of Huntley, Dunkirk and Oswego generating stations. The NOVs allege that a total of 7,231 events had occurred where the average opacity during a six-minute block of time had exceeded 20 percent. The NYDEC proposed a penalty associated with the NOVs at $900,000. NRG is in negotiations with the NYDEC to settle the dispute.

Ashland Manufactured Gas Plant Site — NSP-Wisconsin was named as one of three potentially responsible parties (PRP) 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.

Estimates of the ultimate cost to remediate the Ashland site vary from $4 million to $93 million, depending on the final remediation option chosen by the EPA and the Wisconsin Department of Natural Resources (WDNR). The EPA and WDNR have not yet selected the final method of remediation to use at the site. In the interim, NSP-Wisconsin has recorded a liability for an estimate of its share of the cost of remediating the portion of the Ashland site that it owns, using information available to date, reasonably effective remedial methods and considering the results of ongoing negotiations with governmental authorities overseeing the remediation.

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 2003 or 2004.

Legal Contingencies

California Litigation — Public Utility District No. 1 of Snohomish County, Washington, has filed a suit against Xcel Energy in United States District Court for the Central District of California contending that various 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. Xcel Energy and other defendants requested the case be dismissed in its entirety. A hearing on the motion to dismiss is scheduled for Dec. 19, 2002.

In addition, the California Attorney General’s Office has informed PSCo that it may raise claims against PSCo under the California Business and Professions Code with respect to the rates that PSCo has charged for wholesale sales and PSCo’s reporting of those charges to the FERC. PSCo has had preliminary discussions with the California Attorney General’s Office, and has expressed the view that FERC is the appropriate forum for the concerns that it has raised.

Fortistar Litigation — In July 1999, Fortistar Capital Inc. filed a complaint in District Court in Minnesota against NRG asserting claims for injunctive relief and for damages as a result of NRG’s alleged breach of a confidentiality letter agreement with Fortistar relating to the Oswego facility in New York. NRG disputed Fortistar’s allegations and asserted numerous counterclaims. In October 1999, NRG through a wholly owned subsidiary, closed on the acquisition of the Oswego facility. In April and December 2000, NRG filed summary judgment motions to dispose of the litigation. A hearing on these motions was held in February 2001 and certain of Fortistar’s claims were dismissed. On May 8, 2002 the parties entered into a binding, conditional settlement of the litigation, pending certain approvals and final agreement on the terms of the settlement. Because the conditions for settlement have not been satisfied, the parties have renewed negotiations to explore alternative terms for reaching a settlement.

During the second quarter of 2002, NRG expensed a pre-tax charge of $36 million related to its NEO Corporation landfill gas generation operations, as discussed in Note 2. The charge related largely to asset impairments based on a revised project outlook developed in 2002. It also reflects the accrued impact of the 2002 dispute settlement with Fortistar, a partner with NEO in the Minnesota Methane LLC landfill gas generation operations.

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Shareholder/ERISA Litigation — On July 31, 2002, a lawsuit purporting to be a class action on behalf of purchasers of Xcel Energy common stock between Jan. 31, 2001, and July 26, 2002, was filed in the United States District Court in 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 James J. Howard, former chairman, as defendants. Among other things, the complaint alleges violations of Section 10b of the Securities Exchange Act and Rule 10b-5 related to allegedly false and misleading disclosures concerning various issues, including round trip energy trades, the existence of cross-default provisions in Xcel Energy’s and its subsidiary NRG Energy’s credit agreements with lenders, NRG’s liquidity and credit status, the supposed risks to Xcel Energy’s credit rating and the status of Xcel Energy’s internal controls to monitor trading of its power. Since the filing of the lawsuit, 13 additional, similar lawsuits have been filed on behalf of a similar class of common stock purchasers, seeking similar remedies, one of which has subsequently been voluntarily dismissed. The complaint seeks an unspecified amount of damages, interest, attorneys’ fees and other costs. On Sept. 30, 2002, a further lawsuit making essentially identical allegations, identifying the same class period and seeking the same type of relief was filed in the same court on behalf of a purported class of purchasers of two series of NRG Senior Notes.

On Sept. 23, 2002, an action was filed in the United States District Court in Colorado, on behalf of a purported class of employee participants in certain Xcel Energy employee benefit plans, identifying a class period of Sept. 23, 1999, through the date of filing, and naming Xcel Energy and certain present and former directors and officers as defendants. A second similar action, identifying a class period of Oct. 8, 1999, through the date of filing, followed in the same court. Both actions assert violations of the Employee Retirement Income Security Act of 1974 (ERISA), predicated on essentially the same financial circumstances underlying the class actions and the derivative actions, and asserting breach of fiduciary duty and disclosure violations regarding Xcel Energy stock in the benefit plans. The complaints seek a declaration that defendants violated ERISA, unspecified injunctive relief, restitution, disgorgement and other unspecified relief, interest, attorneys’ fees and other costs.

The defendants in all these actions deny any liability and maintain that their disclosures and other conduct have been fully compliant with applicable laws and reporting requirements.

On Aug. 15, 2002, a shareholder derivative action was filed in the same court as the class actions described above purportedly on Xcel Energy’s behalf, against certain present and former directors and officers of Xcel Energy, citing essentially the same circumstances as the class actions and asserting breach of fiduciary duty. Subsequently, two additional derivative actions were filed in the District Court for Hennepin County, Minnesota against essentially the same defendants, focusing on supposed wrongful energy trading activities and asserting breach of fiduciary duty for failure to establish and maintain adequate accounting controls, abuse of control and gross mismanagement. Collectively, the derivative complaints seek judgment in favor of Xcel Energy for an unspecified amount of damages, return of salaries and other compensation, attorney’s fees and other costs. Xcel Energy and its board of directors will consider the proper manner in which to address the derivative actions, which are ostensibly brought for Xcel Energy’s benefit.

Potential NRG Bankruptcy — As discussed in Notes 6 and 7, NRG continues to work 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. Following an agreement on the restructuring with NRG’s Creditors and as described in Note 6 above, 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; to 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 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 the issue. One of the creditors of an NRG project (Pike, as discussed in Note 4) 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 financial statements do not reflect any conditions or matters that would arise if NRG was in bankruptcy.

LSP Pike Energy, LLC — In August 2002, The Shaw Group (Shaw) and NRG tentatively entered into an agreement to transfer NRG’s interest in the assets in LSP Pike Energy, LLC (Pike) to Shaw. Pike is a 1,200-megawatt, combined-cycle gas turbine plant currently under construction in Mississippi, which is approximately one-third completed. The agreement was subject to approval by the NRG board of directors and lenders. To date, Pike, NRG and its lenders have not approved the agreement. See Note 4 for additional discussion regarding Pike.

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. Due to the uncertainty of the final adjustment, an estimate of the final amount has not been recorded in the results for the quarter ended Sept. 30, 2002.

Conectiv Agreement Termination — On Nov. 8, 2002 Conectiv provided NRG with a Notice of Termination of Transaction under the Master Power Purchase and Sale Agreement (Master PPA) dated June 21, 2001. Under the Master PPA, which was assumed by NRG in its acquisition of various assets from Conectiv, NRG had been required to deliver 500 MW of electrical energy around the clock at a specified price through 2005. In connection with the Conectiv acquisition, NRG recorded an out-of-market contract obligation for this agreement. As a result of the cancellation, NRG will lose approximately $402 million in future contracted revenues. Also, in conjunction with the terms of the Master PPA, NRG will receive from Conectiv a termination payment in the amount of $955,000. At Sept. 30, 2002, the balance of the contract obligation was approximately $54 million.

10. Short-Term Borrowings and Financing Instruments

Xcel Energy Short-Term Borrowings — At Sept. 30, 2002, Xcel Energy and its subsidiaries had approximately $2.0 billion of short-term debt outstanding at a weighted average interest rate of approximately 4.383 percent. See Managements Discussion and Analysis — Financing Activities for discussion of debt issuance in 2002.

On Nov. 8, 2002, Xcel Energy entered into a Securities Purchase Agreement (the Purchase Agreement) with Citadel Equity Fund Ltd., Citadel Credit Trading Ltd. and Jackson Investment Fund Ltd. (together, the Purchasers). Pursuant to the Purchase Agreement, Xcel Energy may issue and sell, in one or more private placements, up to $350 million principal amount of 8 percent senior convertible notes (the Notes). In all cases, the notes shall be issued for a gross amount equal to their principal amount. The Notes are convertible into Xcel Energy’s common stock at any time and from time to time after their issuance date by the holder at the conversion prices described below (subject in each instance to adjustment for stock splits, stock dividends, stock combinations and similar transactions as well as certain issuances by Xcel Energy of common stock or common stock derivative securities). Each of the Notes has an initial maturity of 364 days that can be extended by the holder for additional 364-day periods up to a maximum maturity of 5 years.

The following summary highlights certain material terms of the private placement transactions between Xcel Energy and the Purchasers. Because this is a summary, it does not contain all of the information that is included in the transaction documents and, consequently, is qualified in its entirety by the Purchase Agreement, the Registration Rights Agreement, and the form of Notes, which are attached, or incorporated by reference as exhibits to the this Form 10-Q (the forms of Notes are being refiled with this 10-Q to reflect certain technical corrections) (collectively, the Transaction Documents).

On Nov. 8, 2002, Xcel Energy issued $100 million principal amount of Notes (the First Notes). The conversion price for the First Notes will be 110 percent of the arithmetic average of the weighted average price of Xcel Energy’s common stock for the 20 consecutive trading days commencing on the 5th trading day immediately following the date of issuance (the First Notes Pricing Period) provided (i) that the conversion price shall not exceed $11.59 and (ii) until the end of the First Notes Pricing Period the conversion price shall equal 110 percent of the arithmetic average of the weighted average price of Xcel Energy ‘s common stock for the each of the trading days during the First Call Pricing Period through the date of receipt of a Company Call Notice (as hereinafter defined); and provided further that the conversion price shall be equal to 110 percent of the closing bid price of Xcel Energy’s common stock on the 35th business day following the date of issuance date of the First Notes if Xcel Energy has not delivered a Company Call Notice and such price is less than the conversion price then in effect.

Unless the First Notes have previously been redeemed by Xcel Energy, the sale of $50 million principal amount of Notes (the Second Notes) is expected to occur on Nov. 22, 2002, subject to satisfaction of certain conditions precedent. The conversion price for the Second Notes will be 110 percent of the arithmetic average of the weighted average price of Xcel Energy’s common stock for the 10 consecutive trading days following the First Notes Pricing Period (the Second Notes Pricing Period, and together with the First Notes Pricing Period, the Pricing Periods); provided that (i) the conversion price shall not exceed 110 percent of the weighted average price of Xcel Energy’s common stock on the date of issuance of the Second Notes and (ii) during the Second Notes Pricing Period the conversion price shall equal the lesser of (x) 110 percent of the arithmetic average of the weighted average price of Xcel Energy’s common stock for each of the trading days in the Second Notes Pricing Period through the date of receipt of a Company Call Notice and (y) the weighted average price of the common stock on the date of issuance of the Second Notes; and provided further that the conversion price shall be equal to 110 percent of the closing bid price of Xcel Energy’s common stock on the 35th business day following the issuance date of the First Notes if Xcel Energy has not delivered a Company Call Notice and such price is less than the conversion price then if effect.

The First Notes and the Second Notes are redeemable at the option of Xcel Energy during the period of 35 business days following the issuance of the First Notes upon delivery by Xcel Energy of a notice to the holder of such Notes (the Company Call Notice); provided that Xcel Energy cannot deliver a Company Call Notice unless it has first consummated an offering of convertible debt securities in an underwritten offering resulting in gross proceeds to Xcel Energy of not less than $150 million (a Qualified Offering). Xcel Energy is under no obligation to consummate a Qualified Offering nor is there any obligation on Xcel Energy to redeem the Notes in the event of Xcel Energy’s consummation of Qualified Offering. The closing of any redemption effected by Xcel Energy shall be on the date that is five business days after the 35th business day following the issuance of the First Notes (the Redemption Closing Date). Except as provided above, Xcel Energy may not retire, redeem or otherwise accelerate the final maturity of the Notes.

If Xcel Energy has elected to optionally redeem the Notes, Xcel Energy shall pay to the holders of the Notes in cash the greater of (1) 102 percent of the principal amount, plus accrued interest, on such Notes (the Conversion Amount) and (ii) the sum of (x) the product of the Conversion Amount and the quotient determined by dividing the closing bid price of Xcel Energy’s common stock on the date of the Company Call Notice and the applicable Redemption Conversion Price (as hereinafter defined) and (y) 12 percent of the Conversion Amount of the Note. In addition, Xcel Energy shall deliver to the holders of the Note a written agreement granting the holders the right for a one-year period following the redemption of the Notes to purchase securities identical (other than the issuance date) to the securities issued in the Qualified Offering in an aggregate principal amount of up to 25 percent of the aggregate principal amount of securities issued in the Qualified Offering. The Redemption Conversion Price equals, in the case of the First Notes and the Second Notes, 110 percent of the volume weighted average price of the common stock on the respective dates of issuance of such Notes; provided that if the Company Call Notice is delivered after the initiation of a Pricing Period, then the Redemption Conversion Price shall equal 110 percent of the arithmetic average of the volume weighted average price of the common stock during such period if such price is lower. Under certain circumstance described in the Transaction Documents, the holders of Notes may elect to receive all or a portion of the cash amount described above in shares of Xcel Energy’s common stock by providing notice thereof to Xcel Energy prior to the Redemption Closing Day.

In the event that the Company Call Notice is not delivered within the first 35 business days following the issuance date of the First Notes, from and after such 35th day through and including the one year anniversary date of the issuance of the First Notes, the holders of the Notes shall have the right, at any time and from time to time to purchase up to an additional (i) $50 million of Notes identical (other than the issuance date) to the First Notes (the First Call Notes) and (ii) $25 million of Notes identical (other than the issuance date) to the Second Notes (the Second Call Notes). The holders of the Notes are under no obligation to elect to purchase First Call Notes or Second Call Notes.

In the event that the Company Call Notice is not delivered within the first 35 business days following the issuance date of the First Notes, Xcel Energy may elect to issue and sell to the Purchasers, on a date which is 120 calendar days after the issuance date of the First Notes, up to $100 million principal amount of the Notes (the Third Notes). Xcel Energy’s election to effect such issue and sale (the Company Put) must be made within the 90 calendar days following the issuance date of the First Notes. The conversion price of the Third Notes shall be 110 percent of the arithmetic average of the weighted average price of Xcel Energy’s common stock during the 20 day trading period beginning 90 days after the date of issuance of the First Notes, not to exceed the arithmetic average of the weighted average price of Xcel Energy’s common stock during the 20 day trading period ending on the trading day that is immediately prior to the 90th calendar day after the date of issuance of the First Notes. Xcel Energy’s right to elect the Company Put is subject to certain terms and conditions described in the Transaction Documents. Xcel Energy is under no obligation to elect the Company Put.

At any time and from time to time during the period from the date of issuance of the Third Notes until the date which is 365 days after the date of issuance of the Third Notes, the holders may purchase additional Notes identical to the Third Notes (other than the issuance date) in an aggregate principal amount up to 25 percent of the aggregate principal amount of the Third Notes issued (the Third Call Notes). A holder of Third Notes is under no obligation to elect to purchase Third Call Notes.

Upon the occurrence of a Change of Control (as defined in the Notes), the holders of the Notes may elect to require Xcel Energy to redeem all or any portion of the Notes. The redemption price payable by Xcel Energy in such circumstance is a price equal to the Conversion Amount of such Notes multiplied by the greater of 115 percent and a fraction, the numerator of which is equal to the closing sale price immediately following the public announcement of such proposed Change of Control and a denominator equal to the conversion price applicable to such Notes.

The Notes are also subject to acceleration upon the occurrence of an Event of Default (as defined in the Notes). The coupon rate is subject to increase by 2 percent upon the occurrence of an Event of Default and upon the occurrence of other events described in the Transaction Documents.

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Credit Facilities — As of Sept. 30, 2002, Xcel Energy had the following credit facilities available to meet its liquidity needs:


Company		Total Facility			Drawn		Credit Available		Cash		Total Liquidity		Facility Maturity

	(Millions of dollars)
NSP-Minnesota		$	300		$	100	$	200	$	408	$	609	Aug-2003
NSP-Wisconsin			0			0		0		15		15
PSCo			530			88		442		111		553	June-2003
SPS			250			0		250		78		328	Feb-2003
Xcel Energy -			400	*		400		0					Nov-2002
Holding Company			400			400		0		238		238	Nov-2005
NRG			1,000			1,000		0		347		347	Mar-2003

* This facility matured in November 2002 and was not renewed.

NSP-Minnesota Credit Facility — In August 2002, in connection with its 364-day, $300-million credit agreement renewal, NSP-Minnesota also issued $308 million of first mortgage bonds, due Aug. 15, 2003 to Wells Fargo Bank, N.A. pursuant to the credit agreement. The obligations under the credit agreement will be secured by this series of bonds.

PSCo Credit Facility — In September 2002, PSCo issued and delivered $530 million of first collateral trust bonds to a certain bank to secure its payment obligations under its $530-million, 364-day credit facility.

NRG Short-Term Borrowings — In March 2002, NRG’s $500-million recourse revolving credit facility matured and was replaced with a $1.0-billion, 364-day revolving line of credit, which terminates on March 7, 2003. The facility is unsecured. The credit agreement for this facility was amended in April 2002 to revise the interest coverage ratio covenant. As amended, the covenant requires NRG to maintain a minimum interest coverage ratio that varies throughout the year from 1.75 to 1.00 as determined at the end of each fiscal quarter. The facility contains additional covenants that, among other things, restrict the incurrence of liens and require NRG to maintain a net worth of at least $1.5 billion plus 25 percent of NRG’s consolidated net income from Jan. 1, 2002, through the determination date. In addition, NRG must maintain a debt to capitalization ratio, as defined in the credit agreement, of not more than 0.68 to 1.00. The failure to comply with any of these covenants would be an Event of Default under the terms of the credit agreement At Sept. 30, 2002, NRG had a $1-billion outstanding balance under this credit facility. As of Sept. 30, 2002, the weighted average interest rate of such outstanding advances was 7.7 percent per year. NRG missed the $7.6 million interest payment due on Sept. 30, 2002, and as of Sept. 30, 2002, NRG violated both the minimum net worth covenant and the minimum interest coverage ratio. 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 $1.0-billion, 364-day revolving line of credit. During the second quarter of 2002, the letter of credit facility agreement was amended to incorporate the same covenant revisions and other amendments that had previously been made to the terms and conditions of NRG’s $1-billion revolving credit facility, including the addition of an interest coverage ratio covenant. As of Sept. 30, 2002, NRG violated both the minimum net worth covenant and the minimum interest coverage ratio. Accordingly, the facility is in default.

As of Dec. 31, 2001, NRG, through its wholly owned subsidiary NRG South Central Generating LLC, had outstanding approximately $40 million under a project level, non-recourse revolving credit agreement. In June 2002, this facility was paid off and was not renewed.

NRG Revolving Credit — In May 2001, NRG’s wholly-owned subsidiary, NRG Finance Company I LLC, entered into a $2-billion revolving credit facility. The facility was to be 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 provides for borrowings of base rate loans and Eurocurrency loans and is secured by mortgages and security agreements in respect of the assets of the projects financed under the facility, pledges of the equity interests in the subsidiaries or affiliates of the borrower that own such projects and by guaranties from each such subsidiary or affiliate. Provided that certain conditions are met that assure the lenders that sufficient security remains for the remaining outstanding loans, the borrower may repay loans relating to one project and have the liens relating to that project released. Loans that have been repaid may be re-borrowed, as permitted by the terms of the facility. The facility

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

terminates on May 8, 2006. The facility is non-recourse to NRG other than its obligation to contribute equity at certain times in respect of projects and turbines financed under the facility. As of Sept. 30, 2002, the aggregate amount outstanding under this facility was $1.1 billion, and NRG estimates the obligation to contribute equity to be approximately $819 million. At Sept. 30, 2002, the weighted average interest rate of such outstanding advances was 7.6 percent. Interest and fees due on Sept. 30, 2002 were not paid, and NRG has suspended equity contributions to the project in order to support construction activities. Thus, NRG is currently in default under this facility. See Note 7 for a discussion of the acceleration of debt under this credit facility and for further discussion of NRG’s credit and liquidity contingencies.

Financing Instruments — As of Sept. 30, 2002, Xcel Energy, excluding NRG, had several interest rate swaps with a notional amount of approximately $101 million. If the swaps were terminated at Sept. 30, 2002, Xcel Energy or its subsidiaries would have had to pay the counterparties approximately $18 million. In addition, as of Sept. 30, 2002, NRG had several interest rate swaps with a notional amount of approximately $2.9 billion. If the NRG swaps were terminated at Sept. 30, 2002, NRG would have had to pay the counterparties approximately $112 million.

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. The majority of the guarantees issued by Xcel Energy limit the exposure of Xcel Energy to a maximum amount stated in the guarantees. As of Sept. 30, 2002, Xcel Energy had the following amount of guarantee and exposure under these guarantees:


				Exposure under
Subsidiary		Total Guarantee		Guarantee

		(Millions of dollars)
NRG		$	234	$	104
e prime		$	294	$	78
Viking		$	60	$	60
Other Subsidiaries		$	276	$	81

	Total	$	864	$	323

Xcel Energy guarantees certain obligations for NRG’s power marketing subsidiary, relating to power marketing obligations, fuel purchasing transactions and hedging activities; e prime, relating to trading and hedging activities; and Viking Gas, relating to the Guardian pipeline project. The Viking Gas guarantee terminates no earlier than 90 days after the in-service date of the project. Viking expects the guarantee to terminate in April 2003.

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 Sept. 30, 2002, NRG’s obligations pursuant to its guarantees of the performance, equity and indebtedness obligations of its subsidiaries totaled approximately $687.9 million.

In addition, Xcel Energy provides indemnity protection for bonds issued by subsidiaries. The total amount of bonds with this indemnity outstanding as of Sept. 30, 2002, was approximately $351 million, of which $6.7 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.

11. Derivative Valuation and Financial Impacts

Xcel Energy analyzes derivative financial instruments in accordance with SFAS No. 133. This statement requires that all derivative financial instruments 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 income statement, 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.

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The components of SFAS No. 133 impacts on Xcel Energy’s Other Comprehensive Income, included in stockholders’ equity, are detailed in the following table:


	9 months ended Sept. 30

	2002			2001

	(Millions of dollars)
Balance at Jan. 1	$	34.2		$	—
Net unrealized transition loss at adoption, Jan. 1, 2001		—			(28.8	)
After-tax net unrealized gains related to derivatives accounted for as hedges		69.2			7.2
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(11.9	)		32.2
Acquisition of NRG minority interest		27.4			—

Accumulated other comprehensive income related to SFAS No. 133	$	118.9		$	10.6

The components of the gain for SFAS No. 133 impacts on Xcel Energy’s income statement for the three and nine months ended Sept. 30, 2002 and 2001, excluding gains and losses from trading activities, are detailed in the following table:


		3 months ended						9 Months ended
		Sept. 30						Sept. 30

		2002			2001			2002			2001

		(Millions of dollars, except per share data)
Increase (decrease) in income:
	Nonregulated and other revenues	$	(33.8	)	$	(10.2	)	$	2.5		$	(21.6	)
	Equity earnings from investment in affiliates		1.8			(1.7	)		(0.9	)		(0.9	)
	Electric fuel and purchased power — utility		(0.6	)		(1.2	)		0.4			(1.0	)
	Cost of goods sold — nonregulated and other		(21.3	)		(7.6	)		(21.1	)		(12.8	)
	Other income (deductions)		(2.9	)		(2.2	)		(3.1	)		—

Total decrease before minority interest and income tax		$	(56.8	)	$	(22.9	)	$	(22.2	)	$	(36.3	)

Net-of-tax decrease in net income		$	(33.6	)	$	(11.5	)	$	(15.1	)	$	(13.9	)

Increase (decrease) in EPS-diluted		$	(0.08	)	$	(0.03	)	$	(0.04	)	$	(0.04	)

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

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 their 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.

Xcel Energy evaluates all of its contracts within the regulated and nonregulated operations when such contracts are entered into 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 operations are considered normal under the provisions of SFAS No. 133.

Normal purchases and normal sales contracts are accounted for as executory contracts as required under other generally accepted accounting principles.

Cash Flow Hedges — Xcel Energy and its subsidiaries enter into derivative instruments to manage their 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 Sept. 30, 2002, Xcel Energy had various commodity related contracts extending through 2018. Earnings on

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

these cash flow hedges are recorded as the hedged purchase or sales transaction is completed. This could include the physical sale of electric energy or the usage of natural gas to generate electric energy. Xcel Energy expects to reclassify into earnings through September 2003 net gains from Other Comprehensive Income of approximately $86.4 million.

As required by SFAS No. 133, Xcel Energy recorded losses of $0.6 million and losses of $15.9 million related to ineffectiveness on commodity cash flow hedges during the three months ended Sept. 30, 2002, and 2001, respectively; and gains of $0.4 million and losses of $2.0 million related to ineffectiveness on commodity cash flow hedges during the nine months ended Sept. 30, 2002, and 2001, respectively.

Xcel Energy recorded unrealized losses of $53.1 million and unrealized losses of $1.2 million associated with changes in the fair value of non-hedge, energy-related derivative instruments for the three months ended Sept. 30, 2002 and Sept. 30, 2001, respectively. Xcel Energy recorded unrealized losses of $19.5 million associated with changes in the fair value of non-hedge, energy-related derivative instruments for the nine months ended Sept. 30, 2002. There was no impact for the nine months ended Sept. 30, 2001.

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 through September 2003 net gains from Other Comprehensive Income of approximately $30.6 million.

As a result of various defaults under certain loan agreements, NRG's counterparties have terminated interest rate swaps with NRG, Brazos Valley LP and NRG Finance Company I LLC. As a result of the interest rate swap agreement terminations, the amounts recorded for them as cash flow hedges in Other Comprehensive Income are expected to be relieved from the Other Comprehensive Income account over the remaining period of the debt. Until NRG successfully restructures outstanding debt and returns to credit quality, the company will not seek to manage interest rate risk through the use of financial derivatives.

Xcel Energy records hedge effectiveness 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.

Fair Value Hedges and 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 instruments are available. Xcel Energy does not expect to reclassify any significant amounts into earnings through September 2003 from Other Comprehensive Income on foreign currency swaps accounted for as hedges.

Xcel Energy recorded unrealized losses of $1.0 million and unrealized losses of $2.1 million associated with changes in the fair value of non-hedge, foreign currency derivative instruments for the three months ended Sept. 30, 2002, and Sept. 30, 2001, respectively. Unrealized losses of $0.8 million and unrealized gains of $3,000 associated with changes in the fair value of non-hedge, foreign currency derivative instruments were recorded for the nine months ended Sept. 30, 2002, and Sept. 30, 2001, respectively.

In addition, Xcel Energy recorded losses of $2.3 million related to the discontinuance of hedge accounting for the three and nine months ended Sept. 30, 2002.

Derivatives Not Qualifying for Hedge Accounting — Xcel Energy and its subsidiaries have various trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market basis in our Consolidated Statements of Income. All derivative financial instruments are recorded at the amount of the gain or loss from the transaction within Operating Revenues on the Consolidated Statements of Income.

In order to preserve the U.S. dollar value of projected foreign currency cash flows from European trading operations, Xcel Energy and its subsidiaries enter into various foreign currency exchange contracts that are not designated as accounting hedges but are considered economic hedges. Accordingly, the changes in fair value of these derivatives are reported in Other Nonoperating Income in the Consolidated Statements of Income.

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

12. Segment Information

Xcel Energy has the following reportable segments: Electric Utility, Gas Utility and two of its nonregulated energy businesses, NRG and e prime. Trading operations performed by regulated operating companies are not a reportable segment; electric trading results (net of trading costs) are included in the Electric Utility segment and gas trading results are presented as e prime. In 2002, all other includes $676 million of tax benefits as discussed in Note 14.


		Electric		Gas								All		Reconciling			Consolidated
		Utility		Utility			NRG			e prime		Other		Eliminations				Total

		(Thousands of dollars)
3 months ended Sept. 30, 2002
Operating revenues from external customers		$	1,553,800	$	138,961		$	728,653		$	5,113	$	82,129		—			$	2,508,656
Intersegment revenues			281		(93	)		—			—		24,956		(25,681	)			(537	)
Equity in earnings of unconsolidated affiliates			—		—			26,718			559		693		—				27,970

	Total revenues	$	1,554,081	$	138,868		$	755,371		$	5,672	$	107,778	$	(25,681	)		$	2,536,089

Segment net income (loss)		$	175,427	$	3,127		$	(2,925,314	)	$	2,451	$	684,776	$	(14,427	)		$	(2,073,960	)


		Electric		Gas							All			Reconciling			Consolidated
		Utility		Utility			NRG		e prime		Other			Eliminations			Total

		(Thousands of dollars)
3 months ended Sept. 30, 2001
Operating revenues from external customers		$	1,824,458	$	216,030		$	749,448	$	3,442	$	76,428			—		$	2,869,806
Intersegment revenues			253		1,082			165		—		21,271			(21,959	)		812
Equity in earnings of unconsolidated affiliates			—		—			111,132		323		(434	)		—			111,021

	Total revenues	$	1,824,711	$	217,112		$	860,745	$	3,765	$	97,265		$	(21,959	)	$	2,981,639

Segment net income (loss)		$	183,442	$	(5,295	)	$	141,580	$	1,293	$	(40,103	)	$	(8,014	)	$	272,903


		Electric		Gas							All		Reconciling			Consolidated
		Utility		Utility		NRG			e prime		Other		Eliminations			Total

		(Thousands of dollars)
9 months ended Sept. 30, 2002
Operating revenues from external customers		$	4,114,715	$	937,751	$	1,859,123		$	6,597	$	248,726		—		$	7,166,912
Intersegment revenues			782		663		—			—		67,903		(68,628	)		720
Equity in earnings of unconsolidated affiliates			—		—		68,916			1,266		2,957		—			73,139

	Total revenues	$	4,115,497	$	938,414	$	1,928,039		$	7,863	$	319,586	$	(68,628	)	$	7,240,771

Segment net income (loss)		$	384,875	$	51,965	$	(2,993,129	)	$	1,750	$	701,563	$	(30,178	)	$	(1,883,154	)


		Electric		Gas						All			Reconciling			Consolidated
		Utility		Utility		NRG		e prime		Other			Eliminations				Total

		(Thousands of dollars)
9 months ended Sept. 30, 2001
Operating revenues from external customers		$	5,085,433	$	1,576,732	$	1,852,280	$	15,385	$	249,838			—			$	8,779,668
Intersegment revenues			716		3,241		1,859		—		48,711			(53,384	)			1,143
Equity in earnings of unconsolidated affiliates			—		—		193,875		1,022		3,629			—				198,526

	Total revenues	$	5,086,149	$	1,579,973	$	2,048,014	$	16,407	$	302,178		$	(53,384	)		$	8,979,337

Segment net income (loss)		$	449,926	$	48,464	$	225,872	$	7,131	$	(62,637	)	$	(18,686	)		$	650,070

13. Pension Plan Funding and Costs

As disclosed in the 2001 Annual Report on Form 10-K, all of the Xcel Energy pension plans were fully funded and had no cash funding requirements as of Dec. 31, 2001. Investment performance on plan assets during 2002 has resulted in a deterioration of the funded status of the plans compared to 2001. Xcel Energy’s pension plans, in the aggregate, were still fully funded as of Sept. 30, 2002 and, with minimal investment volatility for the rest of 2002, are expected to remain fully funded at year-end. Depending on final 2002 investment performance, some smaller plans within the group may be underfunded at Dec. 31, 2002.

However, no cash funding to any of Xcel Energy’s pension plans was required for 2002 or is expected for 2003 under ERISA regulations. The level of discretionary funding allowed for 2003 and 2004, if made, would not have a material impact on pension costs. Plan investment performance in the past several years has increased Xcel Energy pension costs due to the difference between assumed asset returns reflected in actuarially determined costs, and actual return levels. Xcel Energy's aggregate annual 2002 pension costs recognized will be approximately $6 million more than comparable 2001 levels. Xcel Energy currently expect that costs to be recognized in 2003 may increase by approximately $40 million in relation to 2002 levels due to the impacts of lower-than-expected asset returns over the past few years.

Depending on final 2002 pension plan investment performance, some of the smaller Xcel Energy plans may have to record a minimum pension liability at Dec. 31, 2002. Based on year-to-date 2002 investment performance, Xcel Energy is estimating that a minimum liability may occur (mainly at PSCo) and be in the range of $100 million to $150 million, with a corresponding reduction in shareholders’ equity (other comprehensive income) for the unrealized loss on pension assets. Recording a minimum pension liability, if necessary, would have no impact on PSCo or Xcel Energy earnings.

14. Income Taxes

As discussed in Note 6, prior to reporting third quarter results for 2002, the likely tax filing status of NRG for 2002 has changed from being included as part of Xcel Energy’s consolidated federal income tax group to filing on a stand-alone basis. On a stand-alone basis, NRG does not have the ability to recognize all tax benefits that may ultimately accrue from losses occurring in 2002. Consequently, current income taxes have been recorded only for refunds actually expected from filing amended returns to carry back 2002 losses to earlier periods, and deferred tax benefits have been recorded only to the extent a tax valuation allowance was not considered necessary.

NRG’s current income tax benefit recognized for the third quarter and nine months ended Sept. 30, 2002 does not include the impact of net pretax operating loss carryforwards of $1.094 billion. In addition, NRG’s deferred tax benefit recognized for the third quarter and nine months ended Sept. 30, 2002 is net of a valuation allowance of $383 million.

The commencement of a loss carryforward position for NRG in the third quarter of 2002 limits the availability of energy tax credits to NRG in 2002, and such credits cannot be carried forward. Accordingly, in third quarter NRG reversed $23 million of 2002 energy tax credits that had previously been recorded through June 30, 2002.

Effective in third quarter 2002, Xcel Energy no longer considers it likely that NRG will be included in Xcel Energy’s consolidated federal income tax group for 2002 tax return purposes. 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 Sept. 30, 2002. This benefit (estimated at $676 million) is reported as deferred income taxes at one of Xcel Energy’s nonregulated intermediate holding companies, and as a reduction of deferred income tax liabilities on the balance sheet. This benefit is based on the difference between the book and tax bases of Xcel Energy’s investment in NRG.

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

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

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “estimate,” “expect,” “objective,” “outlook,” “projected,” “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 the availability of credit, actions of rating agencies and 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;

• 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;

• state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and gas markets;

• the higher risk associated with Xcel Energy’s nonregulated businesses compared with its regulated businesses;

• currency translation and transaction adjustments;

• realization of expectations regarding the NRG financial improvement plan;

• NRG’s ability to reach agreements with its lenders and creditors to restructure its debt;

• risks associated with the California power market; 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 this report on this Form 10-Q.

As discussed more completely under “Liquidity and Capital Resources” and in Notes 2 through 7, NRG’s credit ratings have declined significantly and prices for its power have decreased. As a result, NRG is experiencing severe financial difficulties and has missed several scheduled payments of principal and interest on its bonds. In addition, as a result of being downgraded, NRG is required to post collateral of approximately $1 billion.

NRG had obtained an agreement with various lenders to extend, until Nov. 15, 2002, the deadline by which it must post this cash collateral. As required by the extension agreement, NRG submitted a comprehensive restructuring plan to its lenders and bondholders on Nov. 4, 2002 (see Note 6). The extension agreement did not waive other events of default, including failure to make principal and/or interest payments when due or failure to comply with financial covenants. Nor did the extension agreement waive the rights of the bank group or the bondholders to pursue any rights and remedies in respect of such other defaults.

On Nov. 6, 2002, lenders to NRG accelerated approximately $1.1 billion NRG’s debt under the construction revolver financing facility, rendering the debt immediately due and payable. This action effectively terminated the cash collateral call extension letter in effect between NRG and its major lenders. As mentioned above, the extension letter was previously scheduled to expire Nov. 15, 2002.

Based on discussions with the construction revolver lenders, it is NRG’s understanding that the administrative agent, Credit Suisse First Boston, issued the acceleration notice to preserve certain rights under the construction revolver financing agreements. NRG believes that the administrative agent intends to forbear in the immediate exercise of any rights and remedies against NRG.

NRG has missed several scheduled payments of interest and principal on some of its bonds and does not contemplate making any principal or interest payments on it 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.

As discussed in Note 6, NRG continues to work with its lenders on a comprehensive restructuring plan that would contain waivers and /or material modifications of the collateral requirements and its debt and other obligations. Absent an agreement on this restructuring plan, NRG will be in default under its debt and other obligations because it does not have sufficient funds to meet the requirements and obligations. There can be no assurance that NRG will be able to effect a consensual restructuring or otherwise satisfactorily resolve these issues soon, or at all. It is unlikely that Xcel Energy ultimately will own any equity interest in a restructured NRG.

RESULTS OF OPERATIONS

Earnings per Share Summary

The following table details the earnings per share contribution of Xcel Energy’s regulated and nonregulated businesses.


Earning per share (EPS)		3 months ended:					9 months ended:

		Sept. 30, 2002			Sept. 30, 2001		Sept. 30, 2002			Sept. 30, 2001

Regulated EPS		$	0.49		$	0.53	$	1.23		$	1.52
Nonregulated and holding company EPS:
	Continuing operations		(5.69	)		0.22		(6.29	)		0.32
	Discontinued operations		(0.02	)		0.04		0.05			0.04

Total Xcel Energy EPS		$	(5.22	)	$	0.79	$	(5.01	)	$	1.88

Total earnings have been reduced by NRG asset impairment charges recorded as special charges in the third quarter of 2002, which totaled $2.9 billion before tax and $2.8 billion after tax, or $6.95 per share for the quarter. Other unusual items, including NRG restructuring charges and estimated write-downs and disposal losses for certain NRG projects reduced earnings by an additional $136 million before taxes and $135 million after taxes, or 34 cents per share for the quarter. Year-to-date earnings in 2002 have been reduced by $7.28 per share for the impairment charges and an additional 51 cents per share for other unusual items, including second quarter special charges. In addition, third quarter and year-to-date results include tax benefits of $1.70 and $1.80 per share, respectively, related to Xcel Energy investments in NRG (as discussed in Note 14). Excluding these items, Xcel Energy’s earnings from nonregulated continuing operations would have been a loss of 10 cents per share for the third quarter of 2002 and a loss of 30 cents per share for the nine months ended Sept. 30, 2002. See Note 2 for discussion of special charges.

Xcel Energy issued 23 million shares of common stock in a public offering in February 2002, as well as 25.7 million in June 2002. Dilution from these issuances reduced the loss per share for the quarter and nine-month period ended Sept. 30, 2002, by 73 cents per share and 42 cents per share, respectively. The majority of these dilution impacts are affecting NRG’s special charges, as discussed above.

The components of regulated and nonregulated earnings are discussed in the following sections.

Regulated Results


Earning per share (EPS)		3 months ended:				9 months ended:

		Sept. 30, 2002		Sept. 30, 2001		Sept. 30, 2002			Sept. 30, 2001

Regulated results before unusual items		$	0.49	$	0.53	$	1.25		$	1.49
Conservation incentive recovery			0.00		0.00		0.00			0.07
Special charges — See Note 2			0.00		0.00		(0.02	)		(0.04	)

	Total Regulated Earnings		0.49		0.53		1.23			1.52

The 2002 regulated results before unusual items declined 4 cents and 22 cents per share for the quarter and nine months ended Sept. 30, 2002 largely due to dilution from common stock issuances in 2002. Results for the nine month period also include lower short-term wholesale and trading margins, as discussed in the following section. Dilution reduced third quarter 2002 earnings by 7 cents per share, and reduced year-to-date earnings for 2002 by $0.10 per share. See discussion of special charges recorded earlier in 2002 and in 2001 at Note 2.

2001 Conservation Incentive Recovery — Earnings in the second quarter of 2001 were increased by 7 cents per share due to the reversal of a Minnesota Public Utilities Commission (MPUC) decision.

In June 1999, the MPUC denied NSP-Minnesota recovery of 1998 incentives associated with state-mandated programs for electric energy conservation. Xcel Energy recorded a $35-million charge in 1999, which reduced earnings by 7 cents per share, based on this action. After appeal by NSP-Minnesota, on June 28, 2001, the MPUC approved a plan allowing recovery of the 1998 incentives. 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 now being recorded on a current basis.

Weather — The following summarizes the estimated impact on regulated earnings per share of temperature variations from historical averages (excluding the impact on energy trading operations):


	Earnings per Share Increase (Decrease)

Period Ended Sept. 30:	2002 vs. Normal		2001 vs. Normal		2002 vs. 2001

3 Months Ended	$	0.03	$	0.04	$	(0.01	)
9 Months Ended	$	0.06	$	0.07	$	(0.01	)

Nonregulated and Holding Company Results

The following table summarizes the earnings contributions of Xcel Energy’s nonregulated businesses and holding company results:


Earning per share (EPS)				3 months ended:						9 months ended:

				Sept. 30, 2002			Sept. 30, 2001			Sept. 30, 2002			Sept. 30, 2001

NRG Energy, Inc.:
		Operations before tax credits		$	0.01		$	0.23		$	(0.17	)	$	0.36
		Tax credits			(0.06	)		0.04			0.00			0.10
		Special charges — impairments (Note 2)			(6.95	)		0.00			(7.28	)		0.00
		Special charges — other (Note 2)			(0.04	)		0.00			(0.19	)		0.00
		Write-downs and disposal losses from investments (Notes 2 and 3)			(0.30	)		0.00			(0.32	)		0.00
		Discontinued operations (Note 3)			(0.02	)		0.04			0.05			0.04

			Total NRG Energy, Inc.		(7.36	)		0.31			(7.91	)		0.50
Holding company tax benefit from investment in NRG (Note 14)					1.70			0.00			1.80			0.00
Xcel International, including Yorkshire Power					(0.02	)		(0.02	)		(0.02	)		(0.03	)
Eloigne Company					0.01			0.01			0.02			0.02
Seren Innovations Inc.					(0.01	)		(0.02	)		(0.04	)		(0.06	)
e prime					0.01			0.00			0.00			0.02
Planergy International					0.00			0.00			(0.01	)		(0.02	)
Financing costs and preferred dividends					(0.03	)		(0.03	)		(0.08	)		(0.09	)
Other					(0.01	)		0.01			0.00			0.02

	Total nonregulated and holding company EPS			$	(5.71	)	$	0.26		$	(6.24	)	$	0.36

NRG Operating Results — NRG’s earnings from operations decreased in 2002 due primarily to lower 2002 power prices in the Northeast, Mid-Atlantic and Central regions of the United States and favorable market conditions for West Coast Power in 2001. The decrease for the third quarter was also due to the mark-to-market loss recorded under SFAS No. 133 in the third quarter of 2002 of 13 cents per share, compared with a 3-cent-per-share SFAS No. 133 loss in the comparable 2001 period. NRG’s special charges include estimated losses on sales of certain projects, restructuring costs incurred to date and asset impairment losses, which are discussed in Note 2, and discontinued operations and loss on disposal of equity investments (other assets held for sale), which are discussed in Note 3.

The reversal of previously recorded tax credits in the third quarter of 2002 had an unfavorable impact on NRG’s third quarter 2002 earnings. The reversal of $23 million of tax credits resulted from limitations on credits available to NRG. This reduced NRG’s results by 6 cents per share in the third quarter of 2002 due to changes in NRG’s tax filing status, as discussed in Note 14.

See Note 2 for discussion of NRG special charges in the second and third quarters of 2002. Also, see discussion of NRG tax impacts in Note 14.

Seren — Operation of its broadband communications network in Minnesota and California resulted in losses for the quarter and nine month periods ended Sept. 30, 2002 and 2001 for Seren. As of Sept. 30, 2002, Xcel Energy’s investment in Seren was approximately $251 million. Seren had capitalized $275 million for plant in service and had incurred another $22 million for construction work in progress for these systems at Sept. 30, 2002. Management is continuing to evaluate the strategic fit of Seren in Xcel Energy’s business portfolio.

Planergy International — Planergy is a wholly owned energy management, consulting and demand-side management services subsidiary of Xcel Energy. Planergy’s results for the 9 months ended Sept. 30, 2001 reflect a loss of 2 cents per share recorded in the second quarter of 2001 that was largely due to lower margins on performance contracts, higher project development expenses and final costs related to the consolidation of Planergy and EMI operations.

Financing Costs and Preferred Dividends — Nonregulated and holding company results consist primarily of interest expense and preferred dividend costs, which are incurred at the Xcel Energy and intermediate holding company levels and are not directly assigned to individual subsidiaries.

Income Statement Analysis — Third Quarter 2002 vs. Third Quarter 2001

Electric Utility and Commodity Trading Margins

Xcel Energy’s commodity trading operations are conducted mainly by PSCo (electric) and e prime (gas), both wholly owned subsidiaries. Electric trading activity, initially recorded at PSCo, is partially redistributed to NSP-Minnesota and SPS pursuant to the Joint Operating Agreement (JOA) approved by the FERC. 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 revenue and costs associated with NRG’s operations are included in nonregulated margins. Margins from these generating assets for utility operations are included in short-term wholesale amounts, discussed later. Wholesale and trading margins reflect the impact of regulatory sharing of certain margins under the ICA in Colorado. The following table details electric utility, short-term wholesale and electric and gas trading revenue and margin.


							Electric			Gas
	Electric			Short-term			Commodity			Commodity			Intercompany			Consolidated
	Utility			Wholesale			Trading			Trading			Eliminations			Total

	(Millions of dollars)
3 months ended 9/30/2002
Electric utility revenue	$	1,507		$	50		$	—		$	—		$	—		$	1,557
Electric fuel and purchased power-utility		(578	)		(40	)		—			—			—			(618	)
Electric and gas trading revenue-gross		—			—			540			491			(20	)		1,011
Electric and gas trading costs		—			—			(543	)		(486	)		20			(1,009	)

Gross margin before operating expenses	$	929		$	10		$	(3	)	$	5		$	—		$	941

Margin as a percentage of revenue		61.6	%		20.0	%		(0.6	)%		1.0	%		—			36.6	%
3 months ended 9/30/2001
Electric utility revenue	$	1,622		$	197		$	—		$	—		$	—		$	1,819
Electric fuel and purchased power-utility		(775	)		(173	)		—			—			—			(948	)
Electric and gas trading revenue-gross		—			—			315			389			(16	)		688
Electric and gas trading costs		—			—			(309	)		(386	)		16			(679	)

Gross margin before operating expenses	$	847		$	24		$	6		$	3		$	—		$	880

Margin as a percentage of revenue		52.2	%		12.2	%		1.9	%		0.8	%		—			35.1	%

Short-term wholesale revenues declined by $147 million, and electric utility revenues decreased approximately $115 million in the third quarter of 2002, compared with the same period in 2001, due largely to lower fuel and purchased power costs passed through rate recovery mechanisms and lower revenues from sales of excess capacity in Texas. Electric utility margins increased approximately $82 million for the third quarter of 2002, compared with 2001. The higher electric margins in the third quarter reflect lower unrecovered costs, due in part to resetting the base-cost recovery at PSCo in January 2002 and sales growth.

Electric and gas commodity trading margins and short-term wholesale margins decreased approximately $21 million for the third quarter of 2002, compared with the third quarter of 2001. The decrease reflects lower power prices and less favorable market conditions in 2002.

Gas Utility Margins

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


	3 months ended
	Sept. 30

	2002			2001

	(Millions of dollars)
Gas revenue	$	138		$	217
Cost of gas purchased and transported		(58	)		(136	)

Gas margin	$	80		$	81

Gas revenue decreased by approximately $79 million, or 36.4 percent, in the third quarter of 2002, compared with the same period in 2001, primarily due to decreases 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. Gas margin was approximately the same in both periods.

Nonregulated Operating Margins

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


	3 months ended
	Sept. 30

	2002			2001

	(Millions of dollars)
Nonregulated and other revenue	$	811		$	826
Earnings from equity investments		28			111
Nonregulated cost of goods sold		(455	)		(380	)

Nonregulated margin	$	384		$	557

Nonregulated revenue and margin decreased for the third quarter of 2002, largely due to lower power prices in both consolidated and equity investment projects. Lower power prices, mainly in the United States, reduced demand for NRG’s peaking and merchant power facilities.

Non-Fuel Operating Expense and Other Costs

Utility Other Operation and Maintenance Expenses for the third quarter of 2002 decreased by approximately $29 million, or 7.7 percent, compared with the third quarter of 2001. Lower incentive compensation and other employee benefit costs, as well as lower staffing levels in corporate areas, reduced utility operating and maintenance expense by approximately $10 million for the third quarter of 2002, compared with the same period in 2001. The decreased costs were also due to lower accruals for potentially uncollectible accounts in 2002.

Nonregulated Other Operation and Maintenance Expenses decreased by approximately $3 million, or 1.7 percent, for the third quarter of 2002, compared with the third quarter of 2001, primarily due to the restructuring of NRG’s operations during the third quarter of 2002.

Depreciation and amortization increased by approximately $27 million, or 11.1 percent, for the third quarter of 2002, compared with the third quarter of 2001, primarily due to acquisitions of generating facilities by NRG and capital additions to NRG-owned generation facilities and utility plant additions.

Taxes (other than income taxes) increased largely due to a legislative change in Minnesota in the third quarter of 2001, which reduced annual property taxes by approximately $23 million. The majority of this refund will be returned to NSP-Minnesota customers. In addition, Colorado property taxes for the third quarter of 2001 included an $8 million property tax refund for calendar year 2000.

Special charges in 2002 relate to NRG impairment charges and restructuring costs, as discussed in Note 2. Special charges in 2001 relate to a PSCo regulatory adjustment, also discussed in Note 2.

Estimated loss from disposal of investments relate to several projects pending sale, as discussed in Note 3.

Interest income and other nonoperating income — net of other expenses decreased by approximately $15 million, or 72.9 percent, for the third quarter of 2002, compared with the third quarter of 2001, primarily due to lower interest income at NRG.

Interest expense increased by approximately $32 million, or 16.0 percent, for the third quarter of 2002, compared with the third quarter of 2001, primarily due to increased debt levels to fund several asset acquisitions by NRG and higher borrowings rates and fees at the utility subsidiaries, partially offset by increased amounts of capitalized interest related to NRG’s construction projects.

Income tax expense decreased by approximately $836 million for the third quarter 2002, compared with the third quarter of 2001. Nearly all of this decrease relates to NRG’s 2002 losses and the change in tax filing status for NRG in the third quarter of 2002, as discussed in Note 14. NRG is now in a tax operating loss carryforward and is no longer assumed to be part of Xcel Energy’s consolidated tax group. The effective rate for continuing operations (excluding minority interest) was 24.7 percent for the third quarter of 2002 and 33.8 percent for the third quarter of 2001. The change in the effective rate between years reflects a nominal tax rate at NRG, due to their loss carryforward position. Partially offsetting the NRG tax rate decrease is the impact from a one-time adjustment to recognize tax benefits from Xcel Energy’s investment in NRG, as discussed in Note 14. The effective tax rate for utility and operations other than NRG was comparable for the third quarter 2002, compared with the third quarter 2001.

Discontinued Operations relate to NRG’s assets held for sale as of Sept. 30, 2002, as discussed in Note 3.

Income Statement Analysis — First Nine Months of 2002 vs. First Nine Months of 2001

Electric Utility and Commodity Trading Margins

Xcel Energy’s commodity trading operations are conducted mainly by PSCo (electric) and e prime (gas), both wholly owned subsidiaries. Electric trading activity, initially recorded at PSCo, is partially redistributed to Northern States Power-Minnesota (NSP-Minnesota) and SPS pursuant to the JOA approved by the FERC. 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 revenue and costs associated with NRG’s operations are included in nonregulated margins. Margins from these generating assets for utility operations are included in short-term wholesale amounts, discussed later. Wholesale and trading margins reflect the impact of regulatory sharing of certain trading margins under the ICA in Colorado. The following table details electric utility, short-term wholesale and electric and gas trading revenue and margin.


							Electric			Gas
	Electric			Short-term			Commodity			Commodity			Intercompany			Consolidated
	Utility			Wholesale			Trading			Trading			Eliminations			Total

	(Millions of dollars)
9 months ended 9/30/2002
Electric utility revenue	$	3,985		$	132		$	—		$	—		$	—		$	4,117
Electric fuel and purchased power-utility		(1,544	)		(107	)		—			—			—			(1,651	)
Electric and gas trading revenue-gross		—			—			1,351			1,511			(57	)		2,805
Electric and gas trading costs		—			—			(1,353	)		(1,505	)		57			(2,801	)

Gross margin before operating expenses	$	2,441		$	25		$	(2	)	$	6		$	—		$	2,470

Margin as a percentage of revenue		61.3	%		18.9	%		(0.1	)%		0.4	%		—			35.7	%
9 months ended 9/30/2001
Electric utility revenue	$	4,335		$	675		$	—		$	—		$	—		$	5,010
Electric fuel and purchased power-utility		(2,043	)		(529	)		—			—			—			(2,572	)
Electric and gas trading revenue-gross		—			—			1,075			1,524			(75	)		2,524
Electric and gas trading costs		—			—			(999	)		(1,509	)		75			(2,433	)

Gross margin before operating expenses	$	2,292		$	146		$	76		$	15		$	—		$	2,529

Margin as a percentage of revenue		52.9	%		21.6	%		7.1	%		1.0	%		—			33.6	%

Electric utility revenues decreased approximately $350 million in the first nine months of 2002, compared with the same period in 2001, due largely to lower fuel and power costs passed through rate recovery mechanisms. Electric utility margins increased approximately $149 million for the first nine months of 2002, compared with 2001. The higher electric margins in the first nine months of 2002 reflect lower unrecovered costs, due in part to resetting the base-cost recovery at PSCo in January 2002, sales growth and lower regulatory accruals. Electric utility revenues and margins were both decreased in 2002 due to the 2001 reversal of the disallowed conservation incentive revenues at NSP-Minnesota discussed previously and lower sales of excess capacity in Texas.

Electric and gas commodity trading margins and short-term wholesale margins decreased approximately $208 million, for the first nine months of 2002 compared with the first nine months of 2001. The decrease reflects lower power pool prices and less favorable market conditions in 2002.

Gas Utility Margins


	9 months ended
	Sept. 30

	2002			2001

	(Millions of dollars)
Gas revenue	$	938		$	1,577
Cost of gas purchased and transported		(559	)		(1,200	)

Gas margin	$	379		$	377

Gas revenue decreased by approximately $639 million, or 40.5 percent, in the first nine months of 2002, compared with the same period in 2001, primarily due to decreases 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. Gas margin increased approximately $2 million for the first nine months of 2002, compared with 2001, due largely to the full-period effect of a rate increase effective February 2001 at PSCo.

Nonregulated Operating Margins

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


	9 months ended
	Sept. 30

	2002			2001

	(Millions of dollars)
Nonregulated and other revenue	$	2,108		$	2,102
Earnings from equity investments		73			199
Nonregulated cost of goods sold		(1,137	)		(1,132	)

Nonregulated margin	$	1,044		$	1,169

Nonregulated margin decreased for the first nine months of 2002, largely due to lower power prices in both consolidated and equity investment projects. Lower power prices, mainly in the United States, reduced demand for NRG’s peaking and merchant power facilities.

Non-Fuel Operating Expense and Other Costs

Utility Other Operation and Maintenance Expenses for the first nine months of 2002 decreased by approximately $37 million, or 3.3 percent, compared with the first nine months of 2001. The decreased costs reflect lower incentive compensation and other employee benefit costs, as well as lower staffing levels in corporate areas, partially offset by higher plant outage and property insurance costs.

Nonregulated Other Operation and Maintenance Expenses increased by approximately $108 million, or 23.4 percent, for the first nine months of 2002, compared with the first nine months of 2001, primarily due to the expansion of NRG’s operations during the last nine months of 2001. These portfolio growth costs were partially offset by savings from the restructuring of NRG’s operations during the third quarter of 2002.

Depreciation and amortization increased by approximately $120 million, or 17.9 percent, for the first nine months of 2002, compared with the first nine months of 2001, primarily due to acquisitions of generating facilities by NRG and capital additions to NRG-owned generation facilities and utility plant additions.

Taxes (other than income taxes) increased largely due to an $8 million Colorado property tax refund in 2001 for calendar year 2000.

Special Charges in 2002 included second quarter NRG items previously discussed and first quarter charges for restaffing and regulatory recovery, as discussed in Note 2. Special Charges in 2001 relate to the second quarter PSCo regulatory adjustment, also discussed in Note 2.

Estimated loss from disposal of investments in 2002 relate to several projects pending sale, as discussed in Note 3.

Interest income and other nonoperating income — net of other expenses decreased by approximately $8 million, or 16.4 percent, for the first nine months of 2002, compared with the first nine months of 2001, primarily due to lower interest income at NRG and lower net gains on the sales of assets.

Interest expense increased by approximately $85 million, or 15.4 percent, for the first nine months of 2002, compared with the first nine months of 2001, primarily due to increased debt levels to fund several asset acquisitions by NRG.

Income tax expense decreased by approximately $942 million for the first nine months of 2002, compared with the first nine months of 2001. Nearly all of this decrease, relates to NRG’s 2002 losses and the change in tax filing status for NRG in the third quarter of 2002, as discussed in Note 14. NRG is now in a tax operating loss carryforward and is no longer assumed to be part of Xcel Energy’s consolidated tax group. The effective rate for continuing operations (excluding minority interest) was 24.1 percent for the first nine months of 2002 and 32.1 percent for the first nine months of 2001. The change in the effective rate between years reflects a nominal tax rate at NRG, due to their loss carryforward position. Partially offsetting the NRG tax rate decrease is the impact from a one-time adjustment to recognize tax benefits from Xcel Energy’s investment in NRG, as discussed in Note 14. The effective tax rate for utility and operations other than NRG was comparable for the third quarter 2002, compared with the third quarter 2001.

Discontinued Operations relate to NRG’s assets held for sale as of Sept. 30, 2002, as discussed in Note 3.

Pending Accounting Changes

SFAS No. 143 — In 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 such treatment 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, 2001, Xcel Energy recorded and recovered in rates $623 million of decommissioning obligations and had estimated discounted decommissioning cost obligations to be $878 million as of that date.

In current estimates by Xcel Energy for adoption of the standard on Jan. 1, 2003, the initial value of the liability, including cumulative interest expense through that date, would be approximately $506 million. The decrease in the estimated obligation is due to refinements of assumptions in the SFAS No. 143 calculations, including a higher discount rate and changes in the projected timing and costs for decommissioning (as filed with the MPUC in October 2002). Upon adoption the capitalized asset would be $49 million, before offset by accumulated depreciation of $35 million. The resulting cumulative effect adjustment for unrecognized depreciation and accretion under the new standard would be approximately $8 million. Management expects that the transition amount would be recoverable in rates over time and, therefore, would recognize an additional regulatory asset or liability upon adoption of SFAS No. 143 rather than incur a cumulative effect charge against earnings.

SFAS No. 143 also addresses Xcel Energy’s accrued plant removal costs for a limited number of generation, transmission and distribution facilities for its utility subsidiaries. When identifiable, SFAS No. 143 requires certain removal costs be reclassified from accumulated depreciation to regulatory liabilities when these costs are recoverable in rates. However, these costs are not currently identifiable and the reclassification under SFAS No. 143 may not be practicable.

Xcel Energy expects to adopt SFAS No. 143 as required on Jan. 1, 2003, with updated amounts as appropriate for that date.

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 restructuring plan, if existing debt agreements are ultimately renegotiated. Other impacts of SFAS 145 are not expected to be material to Xcel Energy.

SFAS No. 146 — In July 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 146 may have an impact on the timing of recognition of costs related to the implementation of the NRG restructuring plan; however, such impact is not expected to be material.

EITF Nos. 02-03 and 98-10 — See Note 1 regarding pending changes related to trading operations and the rescission of EITF 98-10 provisions in 2003.

Critical Accounting Policies

Preparation of 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 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 financial statements and related disclosures, even if the nature of the accounting policies applied have not changed. Item 7, Management’s Discussion and Analysis, in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2001 includes 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.

Market Risks

Xcel Energy and its subsidiaries are exposed to market risks, including changes in commodity prices, interest rates and currency exchange rates as disclosed in Management’s Discussion and Analysis in its annual report on Form 10-K for the year ended Dec. 31, 2001. Commodity price risks for Xcel Energy’s regulated subsidiaries are mitigated in most jurisdictions due to cost-based rate regulation.

The energy market continues to evolve and change as market conditions and participants vary. Xcel Energy and its subsidiaries have responded to the change to the energy trading market environment and believe there has been no material change in its market risk exposures that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2001, except as follows:

Interest rates: As a result of various defaults under certain loan agreements, NRG’s counterparties have terminated interest rate swaps with NRG, Brazos Valley LP and NRG Finance Company I LLC. Until NRG successfully restructures outstanding debt and returns to credit quality, the company will not seek to manage interest rate risk through the use of financial derivatives.

Commodity Price: NRG utilizes an undiversified “Value-at-Risk” (VAR) model to estimate a maximum potential loss in the fair value of its commodity portfolio including generation assets, load obligations and bilateral physical and financial transactions. The key assumptions for the NRG Energy VAR model include (1) a lognormal distribution of price returns (2) three day holding period and (3) a 95% confidence interval. The volatility estimate is based on the implied volatility for at the money call options. This model encompasses the following generating regions: Entergy, NEPOOL, NYPP, PJM, WSCC, SPP and Main. The estimated maximum potential three-day loss in fair value of NRG Energy’s commodity portfolio, calculated using the VAR model was $91.6 million and $71.7 million for September 30, 2002 and December 31, 2001, respectively.

LIQUIDITY AND CAPITAL RESOURCES

NRG Financial Issues

Reference is made to Notes 6 and 7 of the Notes to Consolidated Financial Statements for a description of the steps being taken to improve NRG’s financial situation and liquidity issues facing NRG, including the restructuring plan proposed by NRG. As explained in Note 7, Xcel Energy estimates that NRG is required to post collateral ranging from $1.1 billion to $1.3 billion as a result of the lowering of NRG’s credit ratings to below investment grade. NRG previously expected to meet the collateral requirements with available cash, operating cash flows, equity contributions from Xcel Energy, proceeds from asset sales and the issuance of bonds into the capital markets or as a private placement.

NRG had obtained an agreement with various lenders to extend, until Nov. 15, 2002, the deadline by which it must post this cash collateral. As required by the extension agreement, NRG submitted a comprehensive restructuring plan to its lenders and bondholders in late October (see Note 6). The extension agreement did not waive other events of default, including failure to make principal and/or interest payments when due or failure to comply with financial covenants. Nor did the extension agreement waive the rights of the bank group or the bondholders to pursue any rights and remedies in respect of such other defaults.

On Nov. 6, 2002, lenders to NRG accelerated approximately $1.1 billion of NRG's debt under a construction revolver financing facility, rendering the debt immediately due and payable. This action terminated the Second CCEL in effect between NRG and its major lenders. The extension letter was previously scheduled to expire Nov. 15, 2002. Based on discussions with the construction revolver lenders it is NRG's understanding that the administrative agent, Credit Suisse First Boston, issued the acceleration notice to preserve certain rights under the construction revolver financing agreements. NRG believes that the administrative agent intends to forbear in the immediate exercise of any rights and remedies against the Company.

NRG has missed several scheduled payments of interest and principal on some of its bonds and does not contemplate making any principal or interest payments on it 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 may, if they so choose, to seek to enforce their remedies and that would likely lead to a bankruptcy filing by NRG.

As explained in Note 6, NRG submitted to its various lenders, bondholders and other creditor groups (collectively, NRG’s Creditors) a restructuring plan on Nov. 4, 2002. The restructuring plan is expected to serve as a basis to financially restructure NRG and, among other things, proposes the conversion of certain outstanding indebtedness and other obligations of NRG into equity of NRG, addresses the status of each of NRG’s projects and provides for the issuance of NRG debt in satisfaction of various NRG obligations. The restructuring plan includes a proposal addressing Xcel Energy’s continuing role and degree of ownership in NRG and obligations to NRG in a restructured NRG. Based on the advice of its financial advisor that NRG is likely insolvent and in return for a release of any and all claims against Xcel Energy, the plan proposes that, upon consummation of the restructuring, Xcel Energy would pay $300 million to NRG. The plan separately proposes that Xcel Energy surrender its equity ownership of NRG. The plan does not contemplate any sharing by Xcel Energy with NRG’s Creditors of any benefits Xcel Energy might receive in connection with the tax matters described in Note 6. There can be no assurance that the restructuring plan submitted by NRG will be accepted by NRG’s Creditors or that it will not be significantly revised as a result of ongoing negotiations. Furthermore, there can be no assurance that any consensual restructuring plan ultimately will be accepted by NRG’s Creditors.

Whether NRG does or does not reach 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 is 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.

In addition to the collateral requirements, NRG must continue to meet its ongoing operational and construction funding requirements. Since NRG’s 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 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 above, 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.

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 NRG Creditors. Following an agreement on the restructuring with NRG's Creditors and as described in Note 6, 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.

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; to 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 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 the issue. One of the creditors of an NRG project Pike (as discussed in Note 4) 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.

NRG has requested that its financial advisor, Zolfo Cooper, LLC (Zolfo), provide advice to management regarding potential opportunities for, and the general benefits and risks associated with: (a) reducing NRG’s cost structure; (b) improving liquidity and cash flow in the short-, medium- and long-term; (c) mitigating the short-term impact on liquidity and cash flow of certain demands and obligations; and (d) liquidating or monetizing certain assets, including contractual relationships that have net present value based on current market prices. One of the specific areas where NRG management has asked for Zolfo’s assistance is in relation to cash collateral requests. In addition to collateral requirements under the loan documents described above, cash collateral requests have been made of NRG by various contract counterparties as a result of the ratings downgrade at NRG. However, not all of the contract counterparties with the contractual right to request cash collateral under the current circumstances have yet made such a request or demand. Zolfo will be working with NRG management to assess the nature and benefit of each such contractual relationship and to identify and evaluate potential strategies for reducing, mitigating or eliminating each cash collateral request. There are no assurances that NRG can be successful in its efforts to mitigate the cash collateral request issue in a manner that preserves sufficient liquidity to operate its businesses effectively.

Other areas where Zolfo has been asked to assist management include, but are not limited to: (a) managing the working capital impact of certain vendors who previously sold product or provided services to NRG on reasonable, market credit terms, but who are now requiring NRG to pay cash in advance for such product or services; and (b) controlling the general disbursement and commitment process so as to ensure that cash is utilized in a manner that maximizes value for stakeholders. Xcel Energy expects that Zolfo’s involvement will help NRG bring structure to its workout process and institute an appropriate emphasis on short-term liquidity and cash flows.

As explained in Note 10, Xcel Energy had guaranteed at Sept. 30, 2002, approximately $234 million of power market contracts, primarily of the power-marketing subsidiary of NRG. Exposure under these guarantees is approximately $104 million.

As discussed in Note 2, developments in the third quarter of 2002 resulted in material NRG asset impairments of nearly $3 billion before taxes.

NRG may be subject to additional charges and expenses related to the termination of construction and development projects which have not been recorded as of Sept. 30, 2002. Such amounts will be recorded by NRG as they are known and represent a valid claim against the company. NRG is unable to determine the magnitude of these possible charges at this time.

Cash Flows


	9 months ended Sept. 30,

	2002	2001

	(Millions of dollars)
Net cash provided by operating activities	$1,499	$1,338

Cash provided by operating activities increased for the first nine months of 2002, compared with the first nine months of 2001. The increase was primarily due to improved working capital, mainly at NRG due to NRG’s recently implemented cash management procedures. Due to NRG's current liquidity concerns, payment of certain items has been temporarily suspended, pending the completion of the comprehensive restructuring plan.


	9 months ended Sept. 30,

	2002	2001

	(Millions of dollars)
Net cash used in investing activities	$(2,302)	$(4,623)

Cash used in investing activities decreased for the first nine months of 2002, compared with the first nine months of 2001. The change is largely due to decreased levels of nonregulated capital expenditures and asset acquisitions, primarily at NRG.


	9 months ended Sept. 30,

	2002	2001

	(Millions of dollars)
Net cash provided by financing activities	$1,785	$3,364

Cash provided by financing activities decreased for the first nine months of 2002, compared with the first nine months of 2001. The change is largely due to limited financing activities at NRG offset by increased financings at Xcel Energy’s utility subsidiaries.

Capital Requirements

Updated Capital Expenditure Forecast

Utility Capital Requirements — Xcel Energy's utility capital expenditure forecast is detailed in Note 9. The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual construction expenditures may vary from the estimates due to changes in market conditions.

NRG Prospective Capital Requirements — As of Sept. 30, 2002, NRG has taken definitive steps to scale back and delay certain construction projects so as to enhance its financial position and improve liquidity in 2002. See discussion of NRG's capital and operating expenditure forecast in Note 7.

NRG Energy’s capital expenditure program is subject to continuing review and modification. Actual expenditures may differ significantly depending upon such factors as the success, timing of and level of involvement in projects under construction.

NRG Construction Program Sources — NRG has generally financed the acquisition and development of its projects under financing arrangements to be repaid solely from each of its projects cash flows, which are typically secured by the plant’s physical assets and equity interests in the project company. Financing needs are subject to continuing review and can change depending on market and business conditions and changes, if any, in the capital requirements of NRG and its subsidiaries. During the nine months ended Sept. 30, 2002, NRG has financed its acquisition and construction activities through a combination of both short- and long-term corporate level and project level financings, cash infusions from Xcel Energy and to a limited extent operating cash flows. Additional financing sources include cash proceeds from asset sales, as discussed later.

Common Stock Dividends

Until third quarter of 2002, dividends since the Xcel Energy merger have been declared each quarter at a rate of $0.375 per share (equivalent to an annual level of $1.50 per share). On Sept. 26, 2002, Xcel Energy’s board of directors declared a quarterly common stock dividend of $0.1875 per share, a reduction of $0.1875 from the previous dividend. Dividends were paid Oct. 20, 2002. Xcel Energy’s goal is to match future dividend growth with long-term earnings growth.

The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Xcel Energy has outstanding preferred stock, however the restrictions do not place any effective limit on the ability of Xcel Energy to pay dividends.

Capital Sources

Short-Term Funding Sources

In 2002, Xcel Energy has been experiencing some volatility in its funding sources due largely to the credit issues being faced by NRG, as described in Note 7.

NRG Cash Flows and Liquidity — 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 does normally experience higher margins in peak summer periods and lower margins in non-peak periods. NRG has also 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 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. See Note 6 for further discussion of the financial restructuring plan for NRG.

Under the proposed plan, owned assets with un-funded debt service reserve accounts would be funded at the project level over time with operating cash from the projects as it becomes available. The following lists amounts currently required to fund such accounts:


NRG Northeast Generating LLC NRG Peaker Finance Co NRG South Central Generating LLC Mid-Atlantic Generating Flinders Power Finance Pty NRG McClain Enfield	$78.3 million $78.7 million $46.6 million $23.4 million $20.3 million $7.4 million* $3.4 million

*Includes both a debt service reserve and maintenance reserve fund.

NRG estimates that approximately $75 million will be required for general corporate purposes from Oct. 21, through Dec. 31, 2002. This amount includes funds for direct corporate obligations and net requirements for continuing operations. NRG plans to fund these liquidity needs with cash on hand and cash proceeds from asset sales. As of Sept. 30, 2002, NRG had $347 million of cash on hand, which includes $245 million available for general corporate purposes.

Going forward, NRG estimates $125 to $150 million for capital spending in 2003. This amount includes capital improvements, minor refurbishments, and extensions of projects in operation. NRG plans to fund these liquidity needs with cash on hand, operating cash from generating assets, a $300 million infusion from Xcel Energy, and the issuance of project level debt. NRG’s current financial plan estimates cash from operations of approximately $350 million for 2003.

During 2002, Xcel Energy has provided NRG with $500 million of cash infusions. 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 an additional $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.

In the second-quarter 2002, NRG announced it had completed the sale of its ownership interests in an Australian energy company, Energy Development Limited (EDL) and its 50 percent interest in Collinsville Power Station in Australia. NRG received proceeds of approximately $45 million in exchange for its ownership interest in these two assets.

NRG announced the sale of its 60 percent interest in Compania Electrica Central Bulo Bulo S.A. (Bulo Bulo), a Bolivian corporation and TermoRio SA, a Brazilian corporation that owns a thermal generation project under construction in Latin America; transfer of its indirect 50% interest in SRW Cogeneration LP (SRW), which owns a cogeneration facility in Orange County, Texas; and the sales of its 57.7 percent interest in the Crockett Cogeneration Project and sale of its 39.5 percent indirect partnership interest in the Mt. Poso Cogeneration Company, a California limited partnership (Mt. Poso), in California. These transactions are expected to reach financial close in the fourth quarter of 2002 and the company expects to realize net cash proceeds in the amount of approximately $160 million.

As of Sept. 30, 2002, NRG also announced the sales of its Csepel power generating facilities, its 44.5 percent interest in the ECKG power station and its interest in Entrade, an electricity trading business. These transactions are expected to reach financial close in the first quarter of 2003 and the company expects to realize cash proceeds of approximately $200 million. For additional information regarding assets held for sale see Note 3.

Credit Ratings — Short-term borrowings as a source of short-term funding is affected by access to reasonably priced capital markets. This access is dependent in part on credit agency reviews. In the past year, credit ratings for all of Xcel Energy

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 Xcel Energy’s utility operations and corporate financing activities. As of Sept. 30, 2002, the following represents the credit ratings assigned to various Xcel Energy companies:

Company

Credit Type

Moody’s*

Standard & Poors

Fitch*

Xcel Energy

Senior Unsecured Debt

Baa3

BBB-

BB+

Xcel Energy

Commercial Paper

NSP-Minnesota

Senior Unsecured Debt

Baa1

BBB-

BBB

NSP-Minnesota

Senior Secured Debt

BBB+

NSP-Minnesota

Commercial Paper

NSP-Wisconsin

Senior Unsecured Debt

Baa1

BBB

NSP-Wisconsin

Senior Secured Debt

BBB+

PSCo

Senior Unsecured Debt

Baa2

BBB-

BBB

PSCo

Senior Secured Debt

Baa1

BBB+

PSCo

Commercial Paper

SPS

Senior Unsecured Debt

Baa1

BBB

SPS

Commercial Paper

NRG

Corporate Credit Rating

Caa3

N/A

Negative credit watch/negative outlook

Since December 2001, NRG’s access to short-term capital has been limited due to tightening credit standards for the independent power sector as a whole. The unexpected downgrade of NRG’s credit ratings below investment grade in July 2002 has resulted in cash collateral requirements as discussed above and in Note 7. In addition, lower credit ratings have increased the cost of NRG’s capital financing compared to historical levels.

In June 2002, Xcel Energy’s access to commercial paper markets was reduced due to lowered credit ratings (shown above). Management believes these credit ratings for entities other than NRG are unduly low given the separation of NRG’s operations and credit risk from Xcel Energy’s utility operations and corporate financing activities. However, until the ratings are raised, Xcel Energy and its utility subsidiaries continue to seek sources of financing (both short- and long-term) other than commercial paper.

Credit Facilities — On Aug. 15, 2002, NSP-Minnesota obtained an amended and restated credit facility that replaced its $300-million, 364-day fully drawn credit facility. This credit line is structured as a senior revolving facility and is secured by a new series of bonds issued under its First Mortgage Trust Indenture. The new bonds are secured equally with all other bonds outstanding under the Trust Agreement.

Xcel Energy had a $400-million credit facility that expired Nov. 8, 2002. Xcel Energy paid down the $400 million, 364-day bank line on Nov. 8, 2002. Funds to pay down the line came from cash at the Xcel Energy holding company and funds from a new financing, as discussed in Note 10.

See additional discussion regarding credit facilities at Note 10.

Cross Default Provisions — On Aug. 5, 2002, Xcel Energy signed agreements with its lenders to eliminate cross-default provisions in its bank credit agreements with respect to NRG. At the time, Xcel Energy’s bank agreements consisted of a 364-day credit facility in the amount of $400 million expiring in November 2002 and a five-year credit facility in the amount of $400 million expiring in November 2005. The revised agreements removed key provisions in Xcel Energy’s credit facilities that would have constrained Xcel Energy’s ability to access capital due to difficulties faced by NRG in complying with the terms of NRG’s credit facilities. The agreements reached with Xcel Energy’s lenders removed the linkage between NRG’s agreements and credit facilities and those at Xcel Energy by removing the cross-default provisions.

Financing Activities

Xcel Energy Registration Statements — In September 2000, Xcel Energy filed a $1 billion shelf registration with the SEC to issue debt securities. Xcel Energy has approximately $400 million remaining available under this registration.

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 available under this registration.

Xcel Energy Securities Issuances — In February 2002, Xcel Energy issued 23 million shares of common stock at $22.50 per share. The proceeds were used to fund NRG and to repay short-term debt.

In June 2002, Xcel Energy issued 25.7 million shares of common stock to complete its exchange offer with minority NRG shareholders and acquire 100 percent ownership of NRG (see Note 5).

On Nov. 8, 2002, Xcel Energy entered into a securities purchase agreement with institutional investor pursuant to which the investors purchase, in a private placement, $100 million of Xcel Energy 8 percent senior convertible debt securities. The debt securities are convertible into common stock of Xcel Energy. The proceeds were used to help pay down Xcel Energy's 364-day line of credit which came due on Nov. 8. The securities purchase agreement further provides for possible additional financings up to $250 million. See Note 10.

NSP-MN Debt Issuances — In July 2002, NSP-MN issued $185 million of 8-percent public income notes due in 2042. The proceeds were used to repay short-term indebtedness incurred for general working capital purposes and to meet long-term debt maturity requirements.

In August 2002, NSP-Minnesota issued $450 million of first mortgage bonds. These bonds carry a fixed interest rate of 8 percent and mature in 2012.

In August 2002, in connection with its 364-day, $300-million credit agreement renewal, NSP-Minnesota also issued $308 million of first mortgage bonds, due Aug. 15, 2003, to Wells Fargo Bank, N.A. pursuant to the credit agreement. The obligations under the credit agreement will be secured by this series of bonds.

In August 2002, NSP-Minnesota closed on the conversion of several bonds totaling $196 million from variable rate to a fixed rate of 8.5 percent. The first call date on these bonds is Aug. 27, 2012. As part of the conversion, $69 million of the bonds were collateralized with first mortgage bonds. The remaining bonds were collateralized in 1997.

PSCo Debt Issuances — In September 2002, PSCo issued $600 million of first collateral trust bonds at a fixed interest rate of 7.875 percent and maturing in 2012.

In September 2002, PSCo issued and delivered $530 million of first collateral trust bonds to a certain bank to secure its payment obligations under its $530 million, 364-day credit facility and $48.75 million of first collateral trust bonds to an insurance company to secure insurance obligations related to its 5.1-percent pollution control bonds, series due Jan. 1, 2019.

NRG Peaker Finance Company LLC — During the second quarter of 2002, NRG Peaker Finance Company LLC, an indirect wholly owned subsidiary of NRG, issued $325 million of floating rate senior secured bonds. This issue, rated triple-A by Moody’s Investors Service and Standard & Poor’s Ratings Services and due in 2019, provided net proceeds of $250 million. XL Capital Assurance Inc. (XLCA), rated triple-A by Moody’s Investors Service, Standard & Poor’s Ratings Services and Fitch Ratings, will guarantee scheduled principal and interest payments on the bonds. The XLCA guarantee is secured by five peaker power plants totaling approximately 1,318 megawatts.

NRG Energy Center, Inc. — In July 2002, NRG Energy Center, an indirect wholly owned subsidiary of NRG, entered into an agreement allowing it to issue senior secured promissory notes in the aggregate principal amount of up to $150 million. In July 2002, under this agreement, NRG Energy Center, Inc. issued $75 million of bonds in a private placement. Two series of notes were issued in July 2002: the $55 million Series A-Notes, dated July 3, 2002, matures on Aug. 1, 2017, and bears an interest rate of 7.25 percent per annum; and the $20 million Series B-Notes, dated July 3, 2002, matures on Aug. 1, 2017, and bears an interest rate of 7.12 percent per annum. NRG Thermal Corporation, a wholly owned subsidiary of NRG, which owns 100 percent of NRG Energy Center, pledged its interests primarily in all of its district heating and cooling investments throughout the United States, as collateral. A covenant in this facility requires that Xcel Energy maintain no less than 50 percent indirect ownership interest in NRG Thermal.

See further discussion of NRG credit collateral calls, defaults and debt covenants at Notes 7 and 10.

Financing Plans

Xcel Energy may issue $150 million to $250 million of convertible debt at the Xcel Energy Holding Company in the fourth quarter of 2002, subject to favorable market conditions. The proceeds may be used for general corporate purposes.

Xcel Energy currently does not anticipate issuing additional shares of common stock during 2002. If it were to do so, proceeds would be used for general corporate purposes, to repay short-term debt or to fund Xcel Energy’s subsidiaries, including NRG. Xcel Energy continues to assess its potential financing plans.

In accordance with an SEC order under PUHCA granting Xcel Energy general financing authority, Xcel Energy must maintain its common stockholders’ equity at a level at least equal to 30 percent of total capitalization in order to issue securities or guarantees. Xcel Energy received approval from the SEC for temporary authorization to allow common equity to be 24 percent of total capitalization, as discussed in Note 8.

Short-term debt and financial instruments are discussed in Note 10 to the Financial Statements.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Item 2, Management’s Discussion and Analysis — Market Risks.

Item 4. CONTROLS AND PROCEDURES

Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. Within the 90-day period prior to the filing of this report, an evaluation was carried out under the supervision and with the participation of the Company’s management, including the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), of the effectiveness of our disclosure controls and procedures. Based on that evaluation, the CEO and CFO have concluded that the Company’s disclosure controls and procedures are effective.

Subsequent to the date of their evaluation, there have been no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls.

Part II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

In the normal course of business, various lawsuits and claims have arisen against Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. See Notes 4, 7, 8 and 9 of the Financial Statements in this Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 of Xcel Energy’s 2001 Form 10-K and Item 1 of Part II of Xcel Energy’s Form 10-Q for the quarter ended June 30, 2002 for a description of certain legal proceedings presently pending. There are no new significant cases to report against Xcel Energy or its subsidiaries and there have been no notable changes in the previously reported proceedings, except as set forth below.

Light Rail Transit — In February 2001, NSP-Minnesota filed a lawsuit in the federal district court in Minneapolis seeking reimbursement of costs for relocating electric utility lines to allow for construction of a light rail transit (LRT) line in downtown Minneapolis. In May 2001, the Minnesota Department of Transportation and the Metropolitan Council (Defendants) obtained a preliminary injunction requiring NSP-Minnesota to move certain facilities. NSP-Minnesota has complied with the preliminary injunction and utility line relocation has commenced. NSP-Minnesota is capitalizing its costs incurred as construction work in progress. In September 2002, the court granted Defendants' motions for summary judgment and dismissed NSP-Minnesota's claims. NSP-Minnesota reserves its right to appeal. In collateral matters regarding LRT construction, NSP-Minnesota commenced a mandamus action in state court seeking an order requiring Defendants to commence condemnation proceedings concerning an underground substation, access to which is blocked by LRT. In October 2002, the court dismissed NSP-Minnesota's petition. NSP-Minnesota also has commenced an action in state court alleging that LRT construction violates the Minnesota Environmental Rights Act and a separate action in federal district court alleging that the Federal Transit Administration's failure to evaluate certain environmental effects of LRT violates the National Environmental Policy Act.

French Island — NSP-Wisconsin’s French Island plant generates electricity by burning a mixture of wood waste and refuse derived fuel. The fuel is derived from municipal solid waste furnished under a contract with La Crosse County, Wisconsin. In October 2000, the EPA reversed a prior decision and found that the plant was subject to the federal large combustor regulations. Those regulations became effective on Dec. 19, 2000. NSP-Wisconsin did not have adequate time to install the emission controls necessary to come into compliance with the large combustor regulations by the compliance date. As a result, on March 29, 2001, the EPA issued a finding of violation to the company. Although NSP-Wisconsin disputes the EPA decision, if successful, the EPA could impose fines up to $27,500 per day for each violation. On April 2, 2001, a conservation group sent NSP-Wisconsin a notice of intent to sue under the citizen suit provisions of the Clean Air Act.

On July 27, 2001, the state of Wisconsin filed a lawsuit against NSP-Wisconsin in the Wisconsin Circuit Court for La Crosse County, contending that NSP-Wisconsin exceeded dioxin emission limits on numerous occasions between July 1995 and December 2000 at French Island. On Sept. 3, 2002, the Wisconsin Circuit Court approved a settlement between NSP-Wisconsin and the state of Wisconsin. Under terms of that settlement, NSP-Wisconsin paid a penalty of approximately $168,000 and agreed to contribute $300,000 to an environmental project near the plant. The settlement resolves all claims identified in the state’s complaint against NSP-Wisconsin.

On Aug. 15, 2001, NSP-Wisconsin received a Certificate of Authority to install control equipment necessary to bring the French Island plant into compliance with the large combustor regulations. NSP-Wisconsin began construction of the new air quality equipment on Oct. 1, 2001. NSP-Wisconsin has reached an agreement in principle with La Crosse County through which La Crosse County will pay for the extra emissions equipment required to comply with the EPA regulation.

Installation of the control equipment has been completed and source tests on one unit confirm that the unit is now in compliance with the state and federal dioxin standards. NSP-Wisconsin will test the remaining unit during the fourth quarter of 2002.

Potential FirstEnergy Litigation — As discussed in Note 4, FirstEnergy terminated the purchase agreements pursuant to which NRG had agreed to purchase four generating stations for approximately $1.6 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.

Item 3. DEFAULTS UPON SENIOR SECURITIES

NRG has identified the following material defaults with respect to the indebtedness of NRG and its significant subsidiaries.

$350 million of 8.25 percent Senior Unsecured Notes due 2010 issued by NRG

• Failure to make $14.4 million interest payment

$250 million of 8.7 percent Remarketable or Redeemable Securities due 2005 issued by NRG

• Failure to make $10.9 million interest payment

$240 million of 8 percent Remarketable or Redeemable Securities due 2013 issued by NRG

• Failure to make $9.6 million interest payment

$350 million of 7.75 percent Senior Unsecured Notes due in 2011 issued by NRG

• Failure to make $13.6 million interest payment

$500 million of 8.625 percent Senior Unsecured Notes due in 2031 issued by NRG

• Failure to make $21.6 million interest payment

$1.0 billion 364-Day Revolving Credit Agreement dated March 8, 2002, among NRG ABN Amro Bank NV as Administrative Agent and the other parties

• Failure to make $7.6 million interest payment

• Missed minimum interest coverage ratio of 1.75x

• Violated minimum net tangible worth of $1.5 billion

$125 million Standby Letter of Credit Facility dated November 30, 1999, among NRG, Australia and New Zealand Banking Group Limited Administrative Agent, and other parties thereto

• Missed minimum interest coverage ratio of 1.75x

• Violated minimum net tangible worth of $1.5 billion

• Cross default to $1.0 billion revolving line of credit agreement

$2.0 billion Credit Agreement, dated May 8, 2001 among NRG Finance Company I LLC, Credit Suiss First Boston as Administrative Agents, and other parties thereto

• Failure to make $267,000 interest payment

• Failure to make $2.9 million interest payment

• Failure to make $5.4 million interest and fees payment

• Failure to fund equity obligations for construction

• Failure to post collateral requirements due under equity support agreement

$325 million Series A floating rate Senior Secured Bonds due in 2019 issued by NRG Peaker Finance Company LLC

• Failure to remove liens placed on one of the project company assets

• A cross default resulting from failure by NRG Energy to make payments of principal, interest on other amounts due on debt for borrowed money in excess of $50 million in the aggregate

$500 million of 8.962 percent Series A-1 Senior Secured Notes due in 2016 issued by NRG South Central Generating LLC

• Failure to make $20.2 million interest and $12.75 million principal payment

• Failure to fund debt service reserve account

$300 million of 9.479 percent Series B-1 Senior Secured bonds due 2024 issued by NRG South Central Generating LLC

• Failure to make $14.2 million interest payment

• Failure to fund debt service reserve account

$320 million of 8.065 percent Series A Senior Secured Bonds due 2004 by NRG Northeast Generating LLC

• Failure to fund for debt service reserve account

$130 million of 8.824 percent Series B Senior Secured Bonds due 2015 by NRG Northeast Generating LLC

• Failure to fund debt service reserve account

$300 million of 9.29 percent Series C Senior Secured Bonds due 2024 by NRG Northeast Generating LLC

• Failure to fund service reserve account

$580 million Loan Agreement dated June 25, 2001, as amended, among Mid Atlantic Generating LLC, JP Morgan Chase Bank as Administrative Agent, and the other parties thereto

• Failure to fund the debt service reserve account

$554 million, Credit and Reimbursement Agreement dated Nov. 12, 1999, as amended, LSP Kendall Energy LLC among Societe General, as Administrative Agent and the other parties thereto

• Liens placed against project assets

(Pounds) 325 million Amended and Restated Facility Agreement dated, Sept. 5, 2001, among Sterling Luxembourg (no. 3) S.A.R.L., Killingholme Power Limited, Banc of America Securities Limited, as Administrative Agent, and the other parties thereto

• Failure to fund the debt service account

Item 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

The following Exhibits are filed with this report:


4.01		Supplemental Indenture dated Aug. 15, 2002, between PSCo and U.S. Bank Trust National Association, as trustee, creating $48,750,000 principal amount of First Mortgage Bonds Collateral, Series G, due 2019.
4.02		Supplemental Indenture dated as of Sept. 15, 2002, between PSCo and U.S. Bank Trust National Association, as trustee, creating $530,000,000 principal amount of First Mortgage Bonds, Collateral Series I, due 2003.
4.03		Supplemental Indenture dated as of Aug. 15, 2002, between PSCo and U.S. Bank Trust National Association, as trustee, creating $48,750,000 principal amount of First Collateral Trust Bonds, Series No. 7, due 2019.
4.04		Supplemental Indenture dated as of Sept. 15, 2002, between PSCo and U.S. Bank Trust National Association, as trustee, creating $530,000,000 principal amount of First Collateral Trust Bonds, Series No. 9, due 2003.
4.05		Supplemental Indenture dated as of June 1, 2002, between NSP-Minnesota and BNY Midwest Trust Company, as successor trustee, creating $308,000,000 principal amount of First Mortgage Bonds, Series due 2003.
4.06		Supplemental Indenture dated as of July 1, 2002, between NSP-Minnesota and BNY Midwest Trust Company, as successor trustee, creating $69,000,000 principal amount of First Mortgage Bonds, Pollution Control Series S.
4.07		Supplemental Indenture dated Sept. 1, 2002, between PSCo and U.S. Bank Trust National Association, as Trustee, creating $600 million principal amount of 7.875 percent First Collateral Trust Bonds, Series No. 8 due 2012. (Incorporated by reference to PSCo’s Current Report on Form 8-K, dated Sept. 18, 2002.)
4.08		Supplemental Indenture dated Sept. 18, 2002, between PSCo and U.S. Bank Trust National Association, as Trustee, creating $600 million principal amount of 7.875 percent First Mortgage Bonds, Series H due 2012. (Incorporated by reference to PSCo’s Current Report on Form 8-K, dated Sept. 18, 2002.)
4.09		Supplemental Indenture dated Aug. 1, 2002, between NSP-Minnesota and BNY Midwest Trust Company, as Trustee, creating $450 million principal amount of 8 percent First Mortgage Bonds, Series A due Aug. 28, 2012. (Incorporated by reference to NSP-Minnesota’s Current Report on Form 8-K, dated Aug. 22, 2002.)
4.10		Form of First Notes
4.11		Form of Second Notes
4.12		Form of First Call Notes
4.13		Form of Second Call Notes
4.14		Form of Third Notes
4.15		Form of Third Call Notes
4.16		Registration Rights Agreement dated as of Nov. 8, 2002 by and among Xcel Energy Inc. and the Buyers named therein. (Incorporated by reference to Xcel Energy’s Current Report on Form 8-K, dated Nov. 8, 2002)
10.01		Securities Purchase Agreement dated as of Nov. 8, 2002 by and among Xcel Energy Inc. and the investors listed on the Schedule of Buyers attached thereto. (Incorporated by reference to Xcel Energy’s Current Report on Form 8-K/A, dated Nov 8, 2002.)
99.01		Statement pursuant to Private Securities Litigation Reform Act.
99.02		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(b) Reports on Form 8-K

The following reports on Form 8-K were filed either during the three months ended Sept. 30, 2002, or between Sept. 30, 2002, and the date of this report:

July 1, 2002, (filed July 8, 2002) Item 5. Other Events. Re: Xcel Energy receipt of Notice of Violation from the Environmental Protection Agency.

July 25, 2002, (filed Aug. 1, 2002) Item 5. Other Events. Re: Rating Agency actions and other events.

July 31, 2002, (filed Aug. 6, 2002) Item 5 and 7. Other Events and Exhibits. Re: Xcel Energy’s elimination of the cross-default provisions in its bank credit agreements and other events.

Aug. 12, 2002, (filed Aug. 13, 2002) Item 5 and 7. Other Events and Exhibits. Re: Xcel Energy’s submission of CEO and CFO statements under oath in response to the SEC order.

Aug 20, 2002, (filed Aug. 23, 2002) Item 5 and 7. Other Events and Exhibits. Re: Xcel Energy’s announcement that Richard C. Kelly named company’s CFO.

Aug. 22, 2002, (filed Aug. 23, 2002) Item 5 and 7. Other Events and Exhibits. Re: Xcel Energy Offering Memorandum for potential (private placement) purchasers of long-term debt.

Sept. 5, 2002, (filed Sept. 16, 2002) Item 5. Other Events. Re: Xcel Energy’s announcement of completion of re-audit by new auditors, Deloitte & Touche.

Sept. 24, 2002, (filed Sept. 27, 2002) Item 5 and 7. Other Events and Exhibits. Re: Xcel Energy, NRG Energy and The Bank of New York finalize the First Supplement to the Purchase Contract Agreement, dated as of June 6, 2002.

Sept. 26, 2002, (filed Oct. 4, 2002) Item 5 and 7. Other Events and Exhibits. Re: Xcel Energy’s announcement of common stock dividend for third quarter.

Oct. 1, 2002, (filed Oct. 4, 2002) Item 5 and 7. Other Events and Exhibits. Re: Xcel Energy’s wholly owned subsidiary’s, NRG Energy, announcement of the end of the fifteen-day grace period for payment of principal and interest payments of secured bonds.

Oct. 3, 2002, (filed Oct. 24, 2002) Item 5 and 7. Other Events and Exhibits. Re: Xcel Energy’s wholly owned subsidiary’s, NRG Energy, consideration of third quarter 2002 write-downs or abandonments.

Oct. 18, 2002, (filed Oct. 31, 2002) Item 5 and 7. Other Events and Exhibits. Re: Xcel Energy’s wholly owned subsidiary’s, NRG Energy, announcement of agreement reached with its bank lenders to extend until Nov. 15, the deadline by which it must post cash collateral in connection with certain bank loan agreements.

Nov. 8, 2002, (filed Nov. 14, 2002) Item 5 and 7. Other Events and Exhibits. Re: Xcel Energy’s securities purchase agreement with institutional lenders.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	XCEL ENERGY INC.
	(Registrant)

	/s/ DAVID E. RIPKA

	David E. Ripka
	Vice President and Controller

	/s/ RICHARD C. KELLY

	Richard C. Kelly
	Vice President and Chief Financial Officer

Date: November 18, 2002

CERTIFICATIONS

I, Wayne H. Brunetti, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Xcel Energy Inc;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


Date: November 18, 2002
		/s/ Wayne H. Brunetti

		Wayne H. Brunetti Chairman, President and Chief Executive Officer

I, Richard C. Kelly, certify that:


Date: November 18, 2002
		/s/ Richard C. Kelly

		Richard C. Kelly Vice President and Chief Financial Officer

	•		November 2002 — intervenor testimony;

	•		January 2003 — company rebuttal testimony;

	•		February/March 2003 — hearings; and

	•		April/May 2003 — rates effective.

	•		California Power Market — Collectibility of NRG receivables;

	•		Tax Matters — Tax deductibility of corporate-owned life insurance loan interest and

•		general economic conditions, including the availability of credit, actions of rating agencies and 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;

•		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;

•		state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and gas markets;

•		the higher risk associated with Xcel Energy’s nonregulated businesses compared with its regulated businesses;

•		currency translation and transaction adjustments;

•		realization of expectations regarding the NRG financial improvement plan;

•		NRG’s ability to reach agreements with its lenders and creditors to restructure its debt;

•		risks associated with the California power market; 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 this report on this Form 10-Q.

•		Failure to make $7.6 million interest payment

•		Missed minimum interest coverage ratio of 1.75x

•		Violated minimum net tangible worth of $1.5 billion

•		Missed minimum interest coverage ratio of 1.75x

•		Violated minimum net tangible worth of $1.5 billion

•		Cross default to $1.0 billion revolving line of credit agreement

•		Failure to make $267,000 interest payment

•		Failure to make $2.9 million interest payment

•		Failure to make $5.4 million interest and fees payment

•		Failure to fund equity obligations for construction

•		Failure to post collateral requirements due under equity support agreement

•		Failure to remove liens placed on one of the project company assets

•		A cross default resulting from failure by NRG Energy to make payments of principal, interest on other amounts due on debt for borrowed money in excess of $50 million in the aggregate

•		Failure to make $20.2 million interest and $12.75 million principal payment

•		Failure to fund debt service reserve account

•		Failure to make $14.2 million interest payment

•		Failure to fund debt service reserve account

1.		I have reviewed this quarterly report on Form 10-Q of Xcel Energy Inc;

2.		Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.		Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4.		The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

	a)		designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

	b)		evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

	c)		presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

	a)		all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

	b)		any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and