XCEL ENERGY INC - 10-Q Quarterly Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2003

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________________ to ____________________

Commission File Number: 1-3034

Xcel Energy Inc.
(Exact name of registrant as specified in its charter)


Minnesota		41-0448030

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

800 Nicollet Mall, Minneapolis, Minnesota		55402

(Address of principal executive offices)		(Zip Code)

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

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. [X] Yes [ ] No

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). [X] Yes [ ] No

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 July 31, 2003

Common Stock, $2.50 par value		398,751,821 shares

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY AND OTHER COMPREHENSIVE INCOME (UNAUDITED)
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY AND OTHER COMPREHENSIVE INCOME (UNAUDITED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
SIGNATURES
EX-4.01 Supplemental Trust Indenture
EX-10.01 Stock Equivalent Plan
EX-10.02 Separation Agreement
EX-31.01 Certification Pursuant to Section 302
EX-32.01 Certification Pursuant to Section 906
EX-99.01 Statement-Securities Litigation Reform
EX-99.02 Unaudited Pro Forma Financial Information

PART I – FINANCIAL INFORMATION
Item 1. Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(Thousands of Dollars, Except Per Share Data)


			Three Months Ended June 30,						Six Months Ended June 30,

			2003			2002			2003			2002

Operating revenues:
	Electric utility		$	1,378,904		$	1,328,898		$	2,747,874		$	2,560,555
	Natural gas utility			273,556			235,635			939,685			799,546
	Electric and natural gas trading margin			3,693			(405	)		7,267			2,345
	Nonregulated and other			114,862			634,091			222,771			1,189,877
	Equity earnings from unconsolidated NRG affiliates			—			27,528			—			42,198

		Total operating revenues		1,771,015			2,225,747			3,917,597			4,594,521
Operating expenses:
	Electric fuel and purchased power – utility			640,904			544,405			1,233,594			1,032,519
	Cost of natural gas sold and transported – utility			174,893			125,617			654,844			501,232
	Cost of sales – nonregulated and other			69,766			313,896			147,372			590,959
	Other operating and maintenance expenses – utility			381,845			343,983			763,472			735,474
	Other operating and maintenance expenses – nonregulated			38,295			177,892			63,840			372,214
	Depreciation and amortization			210,051			260,324			403,941			508,317
	Taxes (other than income taxes)			81,757			84,708			163,341			167,605
	Special charges (see Note 2)			7,331			60,536			8,772			74,649

		Total operating expenses		1,604,842			1,911,361			3,439,176			3,982,969

Operating income				166,173			314,386			478,421			611,552
Equity in losses of NRG				(351,192	)		—			(363,825	)		—
Minority interest in NRG losses				—			6,788			—			13,580
Interest and other income, net of nonoperating expenses (see Note 12)				10,864			12,168			9,100			33,999
Interest charges and financing costs:
	Interest charges – net of amounts capitalized (includes other financing costs of $4,140, $9,241, $16,493 and $16,665, respectively)			109,928			200,973			215,663			389,578
	Distributions on redeemable preferred securities of subsidiary trusts			9,566			9,472			19,152			19,172

		Total interest charges and financing costs		119,494			210,445			234,815			408,750
Income (loss) from continuing operations before income taxes				(293,649	)		122,897			(111,119	)		250,381
Income taxes (benefit)				(11,087	)		37,280			52,430			70,835

Income (loss) from continuing operations				(282,562	)		85,617			(163,549	)		179,546
Income from discontinued operations, net of tax (see Note 3)				—			1,685			20,999			11,260

Net income (loss)				(282,562	)		87,302			(142,550	)		190,806
Dividend requirements on preferred stock				1,060			1,060			2,120			2,120

Earnings (loss) available to common shareholders			$	(283,622	)	$	86,242		$	(144,670	)	$	188,686

Weighted average common shares outstanding (in thousands):
	Basic			398,717			377,983			398,716			365,972
	Diluted			398,717			378,129			398,716			366,211
Earnings per share – basic and diluted:
	Income (loss) from continuing operations		$	(0.71	)	$	0.23		$	(0.41	)	$	0.49
	Income from discontinued operations			0.00			0.00			0.05			0.03

		Earnings (loss) per share	$	(0.71	)	$	0.23		$	(0.36	)	$	0.52

See Notes to Consolidated Financial Statements

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


				Six Months Ended June 30,

				2003			2002

Operating activities:
	Net income (loss)			$	(142,550	)	$	190,806
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			397,239			528,758
		Nuclear fuel amortization			21,870			24,586
		Deferred income taxes			84,722			18,650
		Amortization of investment tax credits			(13,980	)		(6,958	)
		Allowance for equity funds used during construction			(12,081	)		(4,188	)
		Undistributed equity in losses (earnings) of unconsolidated affiliates, including NRG			367,406			(321	)
		Gain on sale of nonregulated property			—			(6,785	)
		Asset impairments and disposal losses from equity investments			—			25,103
		(Gain) loss on disposal of discontinued operations			(35,799	)		13,842
		Unrealized loss (gain) on derivative financial instruments			15,872			(18,531	)
		Change in accounts receivable			46,861			18,597
		Change in inventories			77,905			20,615
		Change in other current assets			(38,212	)		(113,370	)
		Change in accounts payable			(170,554	)		(125,631	)
		Change in other current liabilities			(54,958	)		(2,803	)
		Change in other noncurrent assets			(22,726	)		(121,072	)
		Change in other noncurrent liabilities			53,475			156,152

			Net cash provided by operating activities		574,490			597,450
Investing activities:
	Utility capital/construction expenditures				(424,023	)		(451,674	)
	Nonregulated capital expenditures and asset acquisitions				(15,998	)		(883,125	)
	Allowance for equity funds used during construction				12,081			4,188
	Investments in external decommissioning fund				(25,769	)		(29,383	)
	Equity investments, loans and deposits				(7,260	)		(286,251	)
	Proceeds from sale of discontinued operations and nonregulated property				122,493			11,152
	Restricted cash				15,500			—
	Collection of loans made to nonregulated projects				—			13,540
	Other investments – net				(31,061	)		(10,941	)

			Net cash used in investing activities		(354,037	)		(1,632,494	)
Financing activities:
	Short-term borrowings – net				212,817			296,776
	Proceeds from issuance of long-term debt				440,706			1,054,201
	Repayment of long-term debt, including reacquisition premiums				(805,933	)		(449,880	)
	Proceeds from issuance of common stock				218			558,191
	Dividends paid				(151,634	)		(270,630	)

			Net cash (used in) provided by financing activities		(303,826	)		1,188,658
Net increase (decrease) in cash and cash equivalents – continuing operations					(83,373	)		153,614
Net decrease in cash and cash equivalents – reclassification of NRG to equity method					(385,055	)		—
Effect of exchange rate changes on cash					(10,848	)		688
Cash and cash equivalents at beginning of period					901,273			341,310

Cash and cash equivalents at end of period				$	421,997		$	495,612

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(Thousands of Dollars)


			June 30,			Dec. 31,
			2003			2002

ASSETS
Current assets:
	Cash and cash equivalents		$	421,997		$	901,273
	Restricted cash			7,500			305,581
	Accounts receivable – net of allowance for bad debts of $28,666 and $92,745, respectively			664,894			961,060
	Accrued unbilled revenues			295,881			390,984
	Materials and supplies inventories – at average cost			187,266			321,863
	Fuel inventory – at average cost			68,986			207,200
	Natural gas inventories – replacement cost in excess of LIFO: $38,658 and $20,502, respectively			76,298			147,306
	Recoverable purchased natural gas and electric energy costs			158,888			63,975
	Derivative instruments valuation – at market			29,730			62,206
	Prepayments and other			179,717			273,770
	Current assets held for sale			—			101,950

		Total current assets		2,091,157			3,737,168

Property, plant and equipment, at cost:
	Electric utility plant			16,893,586			16,516,790
	Nonregulated property and other			1,624,513			8,411,088
	Natural gas utility plant			2,453,635			2,603,545
	Construction work in progress: utility amounts of $888,395 and $856,008, respectively			921,052			1,513,807

		Total property, plant and equipment		21,892,786			29,045,230
Less accumulated depreciation				(9,361,070	)		(10,303,575	)
Nuclear fuel – net of accumulated amortization: $1,080,401 and $1,058,531, respectively				97,298			74,139

		Net property, plant and equipment		12,629,014			18,815,794

Other assets:
	Investments in unconsolidated affiliates			127,892			1,001,380
	Notes receivable, including amounts from affiliates of $0 and $206,308, respectively			3,071			987,714
	Nuclear decommissioning fund and other investments			778,417			732,166
	Regulatory assets			742,797			576,403
	Derivative instruments valuation – at market			1,980			93,225
	Prepaid pension asset			442,866			466,229
	Goodwill – net of accumulated amortization of $581 and $7,000, respectively			7,730			35,538
	Intangible assets – net of accumulated amortization of $3,014 and $18,900, respectively			58,425			68,210
	Other			213,179			364,243
	Noncurrent assets held for sale			—			379,772

		Total other assets		2,376,357			4,704,880

		Total assets	$	17,096,528		$	27,257,842

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(Thousands of Dollars)


			June 30,		Dec. 31,
			2003		2002

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	241,147	$	7,756,261
	Short-term debt			744,556		1,541,963
	Accounts payable			647,558		1,404,135
	Taxes accrued			207,293		267,214
	Dividends payable			75,821		75,814
	Derivative instruments valuation – at market			36,062		38,767
	Other			362,464		749,521
	Current liabilities held for sale			—		515,161
	NRG losses in excess of investment			959,337		—

		Total current liabilities		3,274,238		12,348,836

Deferred credits and other liabilities:
	Deferred income taxes			1,218,657		1,285,312
	Deferred investment tax credits			163,180		169,696
	Regulatory liabilities			587,983		518,427
	Derivative instruments valuation – at market			25,923		102,779
	Benefit obligations and other			541,827		722,264
	Asset retirement obligations (see Note 1)			889,720		—
	Minimum pension liability			128,053		106,897
	Noncurrent liabilities held for sale			—		154,317

		Total deferred credits and other liabilities		3,555,343		3,059,692

Minority interest in subsidiaries				6,457		34,762
Commitments and contingent liabilities (see Note 8)
Capitalization:
	Long-term debt			5,472,213		6,550,248
	Mandatorily redeemable preferred securities of subsidiary trusts			300,000		494,000
	Preferred stockholders’ equity – authorized 7,000,000 shares of $100 par value; outstanding shares: 1,049,800			104,260		105,320
	Common stockholders’ equity – authorized 1,000,000,000 shares of $2.50 par value; outstanding shares: 2003 – 398,731,917; 2002 – 398,714,039			4,384,017		4,664,984

		Total liabilities and equity	$	17,096,528	$	27,257,842

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY AND OTHER COMPREHENSIVE INCOME (UNAUDITED)
(Thousands of Dollars, Except Share Data)


		Common Stock Issued

															Accumulated
						Capital in			Retained			Shares			Other			Total
		Number		Par		Excess of			Earnings			Held by			Comprehensive			Stockholders’
		of Shares		Value		Par Value			(Deficit)			ESOP			Income (Loss)			Equity

Three months ended June 30, 2003 and 2002
Balance at March 31, 2002			370,123	$	925,309	$	3,443,348		$	2,522,096		$	(17,086	)	$	(178,501	)	$	6,695,166

Net income										87,302									87,302
Currency translation adjustments																73,163			73,163
After-tax net unrealized losses related to derivatives (see Note 10)																(4,939	)		(4,939	)
Unrealized gain on marketable securities																2			2

Comprehensive income for the period																			155,528
Dividends declared:
	Cumulative preferred stock of Xcel Energy									(1,060	)								(1,060	)
	Common stock									(148,954	)								(148,954	)
Issuances of common stock – net			986		2,465		21,162												23,627
Acquisition of NRG minority common shares			25,765		64,412		555,222									28,150			647,784
Other										(10	)								(10	)
Repayment of ESOP loans (a)													205						205

Balance at June 30, 2002			396,874	$	992,186	$	4,019,732		$	2,459,374		$	(16,881	)	$	(82,125	)	$	7,372,286

Balance at March 31, 2003			398,714	$	996,785	$	4,038,151		$	38,010		$	—		$	(308,466	)	$	4,764,480

Net income										(282,562	)								(282,562	)
Currency translation adjustments																82,119			82,119
After-tax net unrealized losses related to derivatives (see Note 10)																(5,932	)		(5,932	)
Minimum pension liability																(24,838	)		(24,838	)
Unrealized gain on marketable securities																53			53

Comprehensive income for the period																			(231,160	)
Dividends declared:
	Cumulative preferred stock of Xcel Energy						(1,060	)											(1,060	)
	Common stock						(148,461	)											(148,461	)
Issuances of common stock – net			18		45		173												218

Balance at June 30, 2003			398,732	$	996,830	$	3,888,803		$	(244,552	)	$	—		$	(257,064	)	$	4,384,017

(a) Did not affect cash flows

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY AND OTHER COMPREHENSIVE INCOME (UNAUDITED)
(Thousands of Dollars, Except Share Data)


		Common Stock Issued

															Accumulated
						Capital in			Retained			Shares			Other			Total
		Number		Par		Excess of			Earnings			Held by			Comprehensive			Stockholders’
		of Shares		Value		Par Value			(Deficit)			ESOP			Income (Loss)			Equity

Six months ended June 30, 2003 and 2002
Balance at Dec. 31, 2001			345,801	$	864,503	$	2,969,589		$	2,558,403		$	(18,564	)	$	(179,454	)	$	6,194,477

Net income										190,806									190,806
Currency translation adjustments																48,497			48,497
After-tax net unrealized gains related to derivatives (see Note 10)																20,688			20,688
Unrealized loss on marketable securities																(28	)		(28	)

Comprehensive income for the period																			259,963
Dividends declared:
	Cumulative preferred stock of Xcel Energy									(2,120	)								(2,120	)
	Common stock									(287,788	)								(287,788	)
Issuances of common stock – net			25,308		63,271		494,921												558,192
Acquisition of NRG minority common shares			25,765		64,412		555,222									28,150			647,784
Other										73						22			95
Repayment of ESOP loans (a)													1,683						1,683

Balance at June 30, 2002			396,874	$	992,186	$	4,019,732		$	2,459,374		$	(16,881	)	$	(82,125	)	$	7,372,286

Balance at Dec. 31, 2002			398,714	$	996,785	$	4,038,151		$	(100,942	)	$	—		$	(269,010	)	$	4,664,984

Net income										(142,550	)								(142,550	)
Currency translation adjustments																97,423			97,423
After-tax net unrealized losses related to derivatives (see Note 10)																(60,649	)		(60,649	)
Minimum pension liability																(24,838	)		(24,838	)
Unrealized gain on marketable securities																10			10

Comprehensive income for the period																			(130,604	)
Dividends declared:
	Cumulative preferred stock of Xcel Energy						(1,060	)		(1,060	)								(2,120	)
	Common stock						(148,461	)											(148,461	)
Issuances of common stock – net			18		45		173												218

Balance at June 30, 2003			398,732	$	996,830	$	3,888,803		$	(244,552	)	$	—		$	(257,064	)	$	4,384,017

(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 June 30, 2003, and Dec. 31, 2002; the results of its operations and stockholders’ equity for the three and six months ended June 30, 2003 and 2002; and its cash flows for the six months ended June 30, 2003 and 2002. Due to the seasonality of Xcel Energy’s electric and natural gas sales and variability of nonregulated operations, such interim 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, 2002. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K.

As discussed in Note 5 to the financial statements, during the second quarter of 2003, Xcel Energy changed its accounting and reporting of its subsidiary NRG to the equity method and has reclassified year-to-date 2003 financial results and information related to NRG from the consolidated basis reported as of March 31, 2003. Xcel Energy reclassified certain items in the 2002 statement of operations and balance sheet to conform to the 2003 presentation. These reclassifications had no effect on stockholders’ equity, net income or earnings per share as previously reported.

1. Accounting Change – SFAS No. 143

Xcel Energy adopted Statement of Financial Accounting Standard (SFAS) No. 143 — “Accounting for Asset Retirement Obligations” effective Jan. 1, 2003. As required by SFAS No. 143, future plant decommissioning obligations were recorded as a liability at fair value as of Jan. 1, 2003, with a corresponding increase to the carrying values of the related long-lived assets. This liability will be increased over time by applying the interest method of accretion to the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets.

The impact of the adoption of SFAS No. 143 for Xcel Energy’s utility subsidiaries is described below. The adoption had no income statement impact, due to the deferral of the cumulative effect adjustments required under SFAS No. 143 through the establishment of a regulatory asset pursuant to SFAS No. 71 — “Accounting for the Effects of Certain Types of Regulation.” NRG also adopted SFAS No. 143 in the first quarter of 2003 and recorded a $2.2 million charge, which was considered immaterial for reporting as a cumulative effect adjustment.

Utility Impact of Adopting SFAS No. 143 - Asset retirement obligations were recorded for the decommissioning of two NSP-Minnesota nuclear generating plants, the Monticello plant and the Prairie Island plant. A liability was also recorded for decommissioning of an NSP-Minnesota steam production plant, the Pathfinder plant. Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are licensed to operate until 2013 and 2014, respectively. Pathfinder operated as a steam production peaking facility from 1969 through June of 2000.

A summary of the accounting for the initial adoption of SFAS No. 143 as of Jan. 1, 2003, is as follows:


	Increase (decrease) in:

	Plant			Regulatory			Long-Term
(Thousands of Dollars)	Assets			Assets			Liabilities

Reflect retirement obligation when liability incurred	$	130,659		$	—		$	130,659
Record accretion of liability to adoption date		—			731,709			731,709
Record depreciation of plant to adoption date		(110,573	)		110,573			—
Reclassify pre-adoption accumulated depreciation		662,411			(662,411	)		—

Net impact of SFAS No. 143 on balance sheet	$	682,497		$	179,871		$	862,368

A reconciliation of the beginning and ending aggregate carrying amount of NSP-Minnesota’s asset retirement obligations recorded under SFAS No. 143 is shown in the table below for the six months ending June 30, 2003.


		Beginning						Accretion in		Revisions		Ending
		Balance		Liabilities		Liabilities		Depreciation		To Prior		Balance
(Thousands of Dollars)		Jan. 1, 2003		Incurred		Settled		Expense		Estimates		June 30, 2003

Steam plant retirement		$	2,725	$	—	$	—	$	66	$	—	$	2,791
Nuclear plant decommissioning			859,643		—		—		27,286		—		886,929

	Total liability	$	862,368	$	—	$	—	$	27,352	$	—	$	889,720

The adoption of SFAS No. 143 resulted in the recording of a capitalized plant asset of $131 million for the discounted cost of asset retirement as of the date the liability was incurred. Accumulated depreciation on this additional capitalized cost through the date of adoption of SFAS No. 143 was $111 million. A regulatory asset of $842 million was recognized for the accumulated SFAS No. 143 costs recognized for accretion of the initial liability and depreciation of the additional capitalized cost through adoption date. This regulatory asset was partially offset by $662 million for the reversal of the decommissioning costs previously accrued in accumulated depreciation for these plants prior to the implementation of SFAS No. 143. The net regulatory asset of $180 million at Jan. 1, 2003, reflects the excess of costs that would have been recorded in expense under SFAS No. 143 over the amount of costs recorded consistent with ratemaking cost recovery for NSP-Minnesota. We expect this regulatory asset to reverse over time since the costs to be accrued under SFAS No. 143 are the same as the costs to be recovered through current NSP-Minnesota ratemaking. Consequently, no cumulative effect adjustment to earnings or shareholders’ equity has been recorded for the adoption of SFAS No. 143 in 2003 as all such effects have been deferred as a regulatory asset.

The pro-forma liability to reflect amounts as if SFAS No. 143 had been applied as of Dec. 31, 2002, was $862 million, the same as the Jan. 1, 2003, amounts discussed previously. The pro-forma liability to reflect adoption of SFAS No. 143 as of Jan. 1, 2002, the beginning of the earliest period presented, was $810 million.

Pro-forma net income and earnings per share have not been presented for the years ended Dec. 31, 2002, because the pro-forma application of SFAS No. 143 to prior periods would not have changed net income or earnings per share of NSP-Minnesota due to the regulatory deferral of any differences of past cost recognition and SFAS No. 143 methodology, as discussed previously.

The fair value of the assets legally restricted for purposes of settling the nuclear asset retirement obligations is $835 million as of June 30, 2003.

The adoption of SFAS No. 143 in 2003 will also affect Xcel Energy’s accrued plant removal costs for other generation, transmission and distribution facilities for its utility subsidiaries. Although SFAS No. 143 does not recognize the future accrual of removal costs as a Generally Accepted Accounting Principles (GAAP) liability, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, the Utility Subsidiaries have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the estimated amounts of future removal costs, which are considered regulatory liabilities under SFAS No. 143 that are accrued in accumulated depreciation, are as follows at Jan. 1, 2003:


(Millions of Dollars)
NSP-Minnesota		$	304
NSP-Wisconsin			70
PSCo.			329
SPS			97
Cheyenne			9

	Total Xcel Energy	$	809

2. Special Charges

Special charges included in Operating Expenses include the following:


		Three Months Ended				Six Months Ended

(Millions of Dollars)		June 30, 2003		June 30, 2002		June 30, 2003		June 30, 2002

NRG restructuring costs – severance		$	—	$	20	$	—	$	20
NRG asset impairments and NEO charges			—		36		—		36
NRG losses from equity investment disposals			—		4		—		4
Holding company costs related to NRG			7		—		9		—
Regulatory recovery adjustment			—		—		—		5
Restaffing			—		—		—		9

	Total special charges	$	7	$	60	$	9	$	74

Holding Company Costs (2003) — During the first six months of 2003, the Xcel Energy holding company incurred approximately $9 million for charges related to NRG’s financial restructuring, including $7 million in the second quarter of 2003.

NRG Special Charges (2002) – In the second quarter of 2002, NRG expensed a pretax charge of $20 million, or 4 cents per share, for severance costs for employees who had been terminated as of that date. NRG expensed a pretax charge of $36 million, or 6 cents per share, largely related to asset impairments at its NEO Corp. landfill gas operations. NRG also recorded a charge of approximately $4 million, or 1 cent per share, to write-down the carrying value of its equity investment in the Collinsville Power Station in Australia, based on the price received under a sales agreement.

As discussed further in Note 5 to the financial statements, all of NRG’s results for 2003 are reported in a single line item, Equity in Losses of NRG, due to the deconsolidation of NRG as a result of its bankruptcy filing in May 2003. NRG’s 2003 results do reflect some effects of asset impairments and restructuring costs, which are discussed in Note 5 to the financial statements, but are not presented as a special charge after 2002.

Regulatory Recovery Adjustment (2002) – During the first quarter of 2002, a wholly owned subsidiary of Xcel Energy, Southwestern Public Service (SPS) wrote off approximately $5 million, or 1 cent per share, of restructuring costs relating to costs incurred to comply with legislation requiring a transition to retail competition in Texas, which was subsequently amended to delay the required transition.

Utility Restaffing (2002) - 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 complete 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 restaffing special charges for the first six months of 2003:


		Dec. 31, 2002		Adjustments						June 30, 2003
(Millions of Dollars)		Liability*		To Liabilities **			Payments			Liability*

Employee severance and related costs – NRG		$	18	$	(18	)	$	—		$	—
Employee severance and related costs – Utility and Service Company			13		—			(8	)		5

	Total accrued special charges	$	31	$	(18	)	$	(8	)	$	5

*		Reported on the balance sheet in other current liabilities and in postretirement and other benefit obligations at Dec. 31, 2002 and as other current liabilities at June 30, 2003.

**		The deconsolidation of NRG in 2003 has eliminated this liability from Xcel Energy’s financial reporting (see Note 5).

3. Discontinued Operations

NRG

During 2002, NRG entered into agreements to dispose of four consolidated international projects and one consolidated domestic project. Sales of four of the projects closed during 2002 (Bulo Bulo, Csepel, Entrade and Crockett Cogeneration) and one project (Killingholme) was sold in January 2003. In addition, NRG has also committed to a plan to sell a sixth project (Hsin Yu). Sale of this project is expected to be completed later in 2003.

For 2002, these projects meet the requirements of SFAS No. 144 — “Accounting for the Impairment or Disposal of Long-Lived Assets,” for discontinued operations reporting and, accordingly, operating results and estimated gains or losses on disposal of these projects have been reclassified to discontinued operations for the 2002 periods. Summarized results of operations of NRG discontinued operations for 2002 were as follows:


		Three Months Ended			Six Months Ended

(Thousands of Dollars)		June 30, 2002			June 30, 2002

Operating revenues		$	163,953		$	358,294
Operating and other expenses			152,130			337,174

	Pretax income from discontinued operations		11,823			21,120
Income taxes			464			186

	Income from discontinued operations		11,359			20,934
Pretax loss from disposal			(9,674	)		(9,674	)

	Net income from discontinued operations	$	1,685		$	11,260

As of Jan. 1, 2003, Xcel Energy has reclassified all of its reporting of NRG to the equity method, as discussed in Note 5 to the financial statements. Under the equity method used for 2003 reporting, NRG’s discontinued operations are combined with NRG’s continuing operations and reported as a single item, Equity in Losses of NRG, within Xcel Energy’s earnings from continuing operations. In addition, the assets and liabilities of these discontinued NRG projects as of Dec. 31, 2002, have been reclassified to the held-for-sale category and are reported separately from assets and liabilities of continuing operations for that period. As of June 30, 2003, all assets and liabilities of NRG have been deconsolidated, as discussed in Note 5, due to the change to the equity method to account for NRG.

Xcel Energy reports in its 2002 discontinued operations only those NRG projects classified as discontinued as of May 14, 2003, the date of NRG’s bankruptcy filing. NRG’s reclassification of its discontinued operations subsequent to that date will not affect Xcel Energy reporting.

Viking Gas

In January 2003, Xcel Energy sold Viking Gas Transmission Co. and its interests in Guardian Pipeline, LLC (two interstate natural gas pipelines) for net proceeds of $124 million, resulting in a pretax gain of $36 million ($21 million after tax, or 5 cents per share). This gain has been reported in discontinued operations. Other quarterly and year-to-date operating results of Viking Gas and Guardian in 2003 and 2002, and Viking Gas’ assets and liabilities as of Dec. 31, 2002, were not reclassified to discontinued operations and assets and liabilities held-for-sale, respectively, due to immateriality.

4. NRG Financial Restructuring and Bankruptcy Filing

Since mid-2002, NRG has experienced severe financial difficulties, resulting primarily from lower prices for power and declining credit ratings. These financial difficulties have caused NRG to, among other things, fail to make payments of interest and/or principal aggregating over $400 million on indebtedness of approximately $4 billion and incur asset impairment charges and other costs in excess of $3 billion for the year ended Dec. 31, 2002. These asset impairment charges include write-offs for anticipated losses on sales of several projects as well as anticipated losses related to projects to which NRG has stopped funding.

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

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

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

• $350 million would be paid at or shortly following the effective date of the NRG plan of reorganization. It is expected that this payment would be made in early 2004.

• $50 million also would be paid in early 2004, and all or any part of such payment could be made, at Xcel Energy’s election, in Xcel Energy common stock.

• Up to $352 million would be paid on April 30, 2004, unless at such time Xcel Energy had not received tax refunds equal to $352 million associated with the loss on its investment in NRG. To the extent Xcel Energy had not received such refunds, the April 30 payment would be due on May 30, 2004.

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

Upon the effective date of the NRG plan of reorganization, Xcel Energy’s exposure on any guarantees or other credit support obligations incurred by Xcel Energy for the benefit of NRG or any subsidiary would be terminated and any cash collateral posted by Xcel Energy would be returned. The current amount of such cash collateral is approximately $0.5 million.

As part of the settlement, any intercompany claims of Xcel Energy against NRG or any subsidiary arising from the provision of intercompany goods or services or the honoring of any guarantee will be paid in full in cash in the ordinary course except that the agreed amount of such intercompany claims arising or accrued as of Jan. 31, 2003, will be reduced to $10 million. The $10 million agreed amount is to be paid upon the effective date of the NRG plan of reorganization, with an unsecured promissory note of NRG in the principal amount of $10 million with a maturity of 30 months and an annual interest rate of 3 percent.

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

Consummation of the settlement, including Xcel Energy’s obligations to make the payments set forth above, is contingent upon, among other things, the following:

• The effective date of the NRG plan of reorganization for the NRG voluntary bankruptcy proceeding occurring on or prior to Dec. 15, 2003;

• The final plan of reorganization approved by the bankruptcy court and related documents containing terms satisfactory to Xcel Energy, NRG and various groups of the NRG creditors;

• The receipt of releases in favor of Xcel Energy from holders of at least 85 percent of the general unsecured claims held by NRG’s creditors; and

• The receipt by Xcel Energy of all necessary regulatory and other approvals.

Since many of these conditions are not within Xcel Energy’s control, Xcel Energy cannot state with certainty that the settlement will be effectuated. Nevertheless, Xcel Energy management believes at this time that the settlement will be implemented.

Based on the tax effect of an expected write-off of Xcel Energy’s investment in NRG, Xcel Energy has recognized at June 30, 2003, an estimate of $706 million of the expected tax benefits of the write-off, as discussed in Note 6.

Xcel Energy expects to claim a worthless stock deduction in 2003 on its investment in NRG. This would result in Xcel Energy having a net operating loss for the year for tax purposes. Under current law, this 2003 net operating loss could be carried back two years for federal tax purposes. Xcel Energy expects to file for a tax refund of approximately $355 million in first quarter 2004. This refund is based on a two-year carryback.

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

NRG Voluntary Bankruptcy Petition - On May 14, 2003, Xcel Energy announced that NRG and certain of its affiliates filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code to restructure their debt. Neither Xcel Energy nor any of Xcel Energy’s other subsidiaries were included in the filing.

NRG’s filing included its plan of reorganization and the terms of the overall settlement among NRG, Xcel Energy and members of NRG’s major creditor constituencies that provide for payments by Xcel Energy to NRG and its creditors of up to $752 million. A plan support agreement, reflecting the settlement, has been signed by Xcel Energy, NRG, holders of approximately 40 percent in principal amount of NRG’s long-term notes and bonds along with two NRG banks that serve as co-chairs of the Global Steering Committee for the NRG bank lenders. The terms of the plan support agreement with NRG’s major creditors are basically the same as the terms of the March 26, 2003, settlement discussed previously. The plan support agreement will become effective upon execution by holders of approximately 10 percent in principal amount of NRG’s long-term notes and bonds and by a majority of NRG bank lenders representing at least two-thirds in principal amount of NRG’s bank debt.

NRG filed its voluntary petitions in the United States Bankruptcy Court for the Southern District of New York. As of Dec. 31, 2002, NRG had consolidated company wide (filing and non-filing entities combined) assets of $10.9 billion and liabilities of $11.6 billion.

The following is the expected timeline for NRG to emerge from bankruptcy. We cannot assure that the NRG plan of reorganization will be approved or that NRG will successfully complete the proposed restructuring. In addition to bankruptcy court approval, NRG’s plan of reorganization must be approved by the SEC under PUHCA prior to its becoming effective. Furthermore, each solicitation of any consent in respect of the reorganization plan must be accompanied or preceded by a copy of a report on the plan made by the SEC or an abstract thereof made or approved by the SEC.

• NRG’s disclosure statement filed with the SEC under PUHCA in July 2003;

• SEC acts on NRG’s disclosure statement in September 2003;

• Completion of the solicitation process of NRG’s reorganization in October 2003; and

• Confirmation hearing on NRG’s plan of reorganization in November 2003.

While it is an exception rather than the rule, especially where one of the companies involved is not in bankruptcy, the equitable doctrine of substantive consolidation permits a bankruptcy court to disregard the separateness of related entities, consolidate and pool the entities’ assets and liabilities and treat them as though held and incurred by one entity where the interrelationship between the entities warrants such consolidation. In the event the settlement described above is not effectuated, Xcel Energy believes that any effort to substantively consolidate Xcel Energy with NRG would be without merit. However, it is possible that NRG or its creditors would attempt to advance such claims or other claims under piercing the corporate veil, alter ego, control person or related theories in the NRG bankruptcy proceeding. If a bankruptcy court were to allow substantive consolidation of Xcel Energy and NRG or if another court were to allow other related claims against Xcel Energy, it would have a material adverse effect on Xcel Energy.

On July 22, 2003, Xcel Energy and NRG submitted a joint application to the Federal Energy Regulatory Commission (FERC) requesting approval for Xcel Energy to dispose of its interest in NRG by implementing the proposed plan of reorganization filed in the bankruptcy proceedings. The applicants requested a 30-day comment period and FERC approval as expeditiously as possible, but no later than Oct. 22, 2003.

Financial Impacts of NRG’s Bankruptcy - As a result of the bankruptcy filing on May 14, 2003, Xcel Energy has discontinued the consolidation of NRG retroactive to Jan. 1, 2003, and for the year 2003 and is reporting NRG results under the equity method of accounting. See Note 5 for further discussion of the impacts of deconsolidating NRG in 2003.

Prior to NRG’s bankruptcy filing on May 14, 2003, Xcel Energy had recognized NRG losses in excess of its investment in NRG, as discussed in Note 5 to the financial statements. Xcel Energy’s exposure to NRG losses subsequent to its deconsolidation is limited under the equity method to Xcel Energy’s financial commitments to NRG. The estimated financial commitment to NRG, based on the terms of the settlement agreement (discussed previously), includes total Xcel Energy settlement payments related to NRG of $752 million. NRG losses recognized in excess of the $752 million in settlement payments will be reversed and recognized as a non-cash gain upon NRG’s emergence from bankruptcy. However, should the settlement agreement not ultimately be approved by NRG’s creditors and/or the bankruptcy court, the amount of financial assistance committed to NRG could be different from those amounts, pending the ultimate resolution of NRG’s bankruptcy. Prior to reaching the settlement agreement, Xcel Energy and NRG had entered into a support and capital subscription agreement in 2002 pursuant to which Xcel Energy agreed, under certain circumstances, to provide a $300 million contribution to NRG.

In addition to the effects of NRG’s losses, Xcel Energy’s operating results and retained earnings in 2003 could also be affected by future tax effects of any financial commitments to NRG, if such income tax benefits were considered likely to be realized in the foreseeable future. See Note 6 for further discussion of tax benefits related to Xcel Energy’s investment in NRG.

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

5. Change in Accounting for NRG

As discussed in Note 4, on May 14, 2003, Xcel Energy’s wholly owned subsidiary NRG filed a voluntary case to restructure its obligations under Chapter 11 of the U.S. Bankruptcy Code in the Bankruptcy Court in the Southern District of New York. NRG plans to begin soliciting its existing creditors for approval of a plan of reorganization based on a settlement agreement (also discussed in Note 4), which contemplates payments by Xcel Energy of up to $752 million. If NRG’s creditors and the bankruptcy court approve the NRG plan of reorganization as presented, Xcel Energy anticipates that its ownership interest in NRG will be completely divested to NRG’s creditors in the future. Xcel Energy cannot assure that the NRG plan of reorganization as proposed will be approved or that NRG will successfully complete the proposed restructuring.

Prior to NRG’s bankruptcy filing, Xcel Energy accounted for NRG as a consolidated subsidiary. However, as a result of NRG’s bankruptcy filing, Xcel Energy no longer has the ability to control the operations of NRG. Accordingly, effective as of the bankruptcy filing date, Xcel Energy ceased the consolidation of NRG and began accounting for its investment in NRG using the equity method in accordance with Accounting Principles Board Opinion No. 18 - “The Equity Method of Accounting for Investments in Common Stock.” As discussed in the next paragraph, after changing to the equity method, Xcel Energy is limited in the amount of NRG’s losses subsequent to the bankruptcy date that it must record.

In accordance with limitations under the equity method, as of June 30, 2003 Xcel Energy has stopped recognizing equity in the losses of NRG. These limitations provide for loss recognition until Xcel Energy’s investment is written off to zero, and then to continue if financial commitments exist beyond amounts already invested. As of May 14, 2003, Xcel Energy had recognized NRG losses to the point where they exceeded the investment made in NRG to date by $867 million, $115 million more than the amount of the $752 million financial commitment to NRG under the settlement agreement discussed previously. The losses recognized in excess of the financial commitment will be reversed and recognized as a non-cash gain upon NRG’s emergence from bankruptcy. If the final amount of financial commitments changes as a result of bankruptcy proceedings, the level of equity in NRG losses recorded by Xcel Energy would also change accordingly at that time. Xcel Energy has reflected these excess losses as a negative investment on the accompanying balance sheet in other current liabilities, based on its expectation that NRG’s plan of reorganization will take effect, and the settlement payments will be made, within 12 months of the bankruptcy filing.

At the time of NRG’s bankruptcy filing, Xcel Energy’s negative investment was greater than its financial commitment to NRG. Therefore, no NRG losses for the post-bankrupcty period have been recognized by Xcel Energy. Beginning with June 30, 2003 quarterly reporting (the first period that includes the bankruptcy filing date), Xcel Energy has reclassified the 2003 net operating results of NRG as equity in losses of NRG in the statement of operations retroactive to Jan. 1, 2003, as permitted under the accounting rules governing a mid-year change from consolidating a subsidiary to accounting for the investment using the equity method. However, the presentation of NRG in the historical financial statements as a consolidated subsidiary in 2002 and prior periods will not change from the prior presentation.

NRG’s stockholders’ equity as of June 30, 2003, can be reconciled to Xcel Energy’s recorded investment in NRG as of that date and to the pro-forma investment in NRG, including expected effects of divesting NRG and implementing the settlement agreement, as follows (in millions):


	Stockholders’ Equity per NRG 10-Q		$	(1,278	)
	NRG Losses Not Recorded by Xcel Energy			257	*
	Purchase Accounting Adjustments			62	**

		Xcel Energy’s Negative Investment in NRG – Liability		(959	)
Pro-forma adjustments to reflect divestiture of NRG and settlement terms:
	Reclassification of NRG’s Other Comprehensive Income			56
	Reclassification of Intercompany Receivables to Investment			36

		Pro-forma Negative Investment in NRG	$	(867	)

	Losses Recognized in Excess of Financial Commitments			115

		Level of Financial Commitments to NRG	$	(752	)

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

**		These relate to Xcel Energy’s June 2002 purchase of NRG’s minority shares and are not reflected in NRG’s financial statements.

Xcel Energy’s negative investment in NRG of $867 million will be eliminated over time through the reversal of $115 million in excess losses upon NRG’s emergence from bankruptcy and through $752 million of expected cash settlement payments as described in Note 4.

NRG’s loss for the three and six month periods ended June 30, 2003, can be reconciled to Xcel Energy’s recorded equity in losses of NRG as follows:


		3 months ended			6 months ended
(in millions)		June 30, 2003			June 30, 2003

Total NRG loss*		$	(608	)	$	(621	)
Losses not recorded by Xcel Energy under the equity method**			257			257

	Equity in losses of NRG included in Xcel Energy results	$	(351	)	$	(364	)

*		Includes discontinued operations related to several projects that have been sold or are pending sale by NRG. For 2003 reporting, no distinction is made under the equity method for the underlying NRG projects, whether discontinued or continuing.

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

NRG Summarized Financial Information – In 2003, Xcel Energy maintained a significant investment in NRG. The following is summarized financial information for NRG for the periods in 2003 for which NRG was not consolidated:

Results of Operations


	3 Months Ended			6 Months Ended

(Millions of dollars)	June 30, 2003			June 30, 2003

Operating revenues	$	536		$	1,121
Operating income (loss)		(490	)		(464	)
Net income (loss)		(608	)		(621	)

Financial Position


(Millions of dollars)		June 30, 2003

Current assets		$	1,496
Other assets			8,515

	Total assets	$	10,011

Current liabilities		$	2,186
Other liabilities			9,103
Stockholder’s equity			(1,278	)

	Total liabilities and equity	$	10,011

NRG’s results in 2003 (before the Xcel Energy limitations under the equity method) include asset impairment charges and financial restructuring costs. As discussed previously, Xcel Energy has not included in its results all of NRG’s losses due to limitations under the equity method of accounting.

NRG asset impairments and related charges in 2003 include approximately $40 million in first quarter charges related to NRG’s NEO landfill gas projects and equity investments and approximately $500 million in second quarter charges. The impairment and related charges in the second quarter of 2003 resulted from planned disposals of the Loy Yang project in Australia and the McClain and Brazos Valley projects in the United States, and regulatory developments and changing circumstances throughout the second quarter that adversely affected NRG’s ability to recover the carrying value of certain Connecticut merchant generation units. Losses of $263 million related to the Connecticut facilities and Brazos Valley were recorded by NRG as of May 14, 2003 and accordingly recorded by Xcel Energy, prior to NRG’s bankruptcy filing.

Restructuring costs incurred by NRG were $20 million for the quarter and $41 million for the six months ended June 30, 2003. Restructuring costs relate to financial and legal advisers, employee severance and other activities related to NRG’s financial restructuring and bankruptcy process.

6. Estimated Income Tax Benefits Related to Xcel Energy’s Investment in NRG

Based on the foreseeable effects of a settlement agreement with the major NRG creditors, including an expected write-off of Xcel Energy’s investment in NRG for tax purposes, Xcel Energy recognized an estimate of the expected tax benefits of the write-off in 2002 in the amount of $706 million. This benefit is based on the estimated tax basis of Xcel Energy’s investments in NRG, and their deductibility for federal tax purposes, upon completion of NRG’s bankruptcy proceeding. See Note 4 for further information on the timing of cash flows related to these estimated tax benefits.

Xcel Energy is currently evaluating additional tax benefits that may be available related to its investment in NRG. These evaluations include an analysis of potential state tax effects of the NRG investment write-off and refinements of Xcel Energy’s tax basis calculations. Assuming these evaluations are completed as expected later in 2003, additional tax benefits may be recorded at that time, which could increase Xcel Energy’s cumulative income tax benefits related to the investment in NRG by up to $100 million. The actual amount of such additional tax benefits, if any, cannot be determined at this time.

In addition, future tax benefits associated with the expected settlement payments of $752 million (discussed in Note 4) will likely be reflected once NRG’s creditors approve the NRG plan of reorganization. Assuming all settlement payments are fully deductible, additional tax benefits of more than $260 million could be recorded later in 2003, at the time that such benefits are considered likely of realization. The timing of recording these benefits would be based on a judgment as to when the settlement payments to NRG become probable for tax purposes.

7. Rates and Regulation

NSP-Minnesota Service Quality Investigation – As previously reported, the Minnesota Public Utilities Commission (MPUC) directed the Office of the Attorney General and the Department of Commerce (state agencies) to investigate the accuracy of NSP-Minnesota’s reliability records. On Aug. 4, 2003, the state agencies jointly filed with the MPUC a report issued by Fraudwise, an investigation firm. Fraudwise had previously been engaged by the state agencies to investigate the validity of allegations involving the integrity of NSP-Minnesota’s service quality reporting. The findings of the Aug. 4, 2003 report are generally consistent with the previously disclosed findings in Fraudwise’s preliminary report that our record keeping contains inconsistencies and misstatements and that it would be nearly impossible to establish the magnitude of misstatements in the record keeping system. The report also states that NSP-Minnesota’s records were unreliable and appear to have been manipulated by a small number of employees to ensure compliance with state-imposed standards. NSP-Minnesota is continuing its internal review of these matters and has taken certain remedial actions to address the record keeping deficiencies. The MPUC has indicated that it is reviewing the report and expects to have a hearing on the matters addressed in the report within two to four months.

The South Dakota Public Utilities Commission (SDPUC) recently indicated an intention to open an investigation into service quality issues. In particular, the investigation would focus on NSP-Minnesota operations in the Sioux Falls area, which has experienced a number of recent power outages. NSP-Minnesota is working with the SDPUC to provide information and to answer inquiries regarding service quality. No docket has been opened.

Midwest Independent Transmission System Operator, Inc. (MISO) Electric Market Initiative (NSP-Minnesota and NSP-Wisconsin) - On July 25, 2003, MISO filed proposed changes to its regional open access transmission tariff to implement a new transmission and energy markets tariff that would establish certain wholesale energy and transmission service markets based on locational marginal cost pricing (LMP) effective in 2004. NSP-Minnesota and NSP-Wisconsin presently receive transmission services from MISO for service to their retail loads and would be subject to the new tariff, if approved by the FERC. Xcel Energy continues to review the filing, but believes the new tariff, if approved by the FERC, could have a material effect on wholesale power supply or transmission service costs to NSP-Minnesota and NSP-Wisconsin beginning in 2004.

FERC Investigation Against All Wholesale Electric Sellers/California Refund Proceedings (PSCo) On June 25, 2003, the FERC issued a series of orders addressing the California electricity markets. Two of these were show cause orders. In the first show cause order, the FERC found that 24 entities may have worked in concert through partnerships, alliances or other arrangements to engage in activities that constitute gaming and/or anomalous market behavior. The FERC initiated the proceedings against these 24 entities requiring that they show cause why their behavior did not constitute gaming and/or anomalous market behavior. PSCo was not named in this order. In a second show cause order, the FERC indicated that various California parties, including the California Independent System Operator (CAISO), have alleged that 43 entities individually engaged in one or more of seven specific types of practices that the FERC has identified as constituting gaming or anomalous market behavior within the meaning of the CAISO and California Power Exchange tariffs. PSCo was listed in an attachment to that show cause order as having been alleged to have engaged in one of the seven identified practices, namely circular scheduling. In the second show cause order, FERC required the CAISO to provide the named entities with “all of the specific transaction data” for each of the seven practices. The CAISO provided that information on July 16, 2003. This data does not list PSCo as among the entities that allegedly engaged in circular scheduling. PSCo may have been named in the show cause order because of a trader telephone conversation transcript that PSCo had previously submitted to the FERC. This transcript was cited in witnesses testimony filed with FERC. The circular scheduling reference in the transcript was by a trader from another company discussing a transaction that did not involve PSCo. PSCo is preparing a motion to dismiss.

Pacific Northwest FERC Refund Proceeding (PSCo) On June 25, 2003, the FERC terminated the proceeding without refunds or ordering further proceedings.

PSCo General Rate Case - In May 2002, PSCo filed a combined general retail electric, natural gas and thermal energy base rate case with the Colorado Public Utilities Commission (CPUC) as required in the merger approval agreement with the CPUC to form Xcel Energy. On April 4, 2003, a comprehensive settlement agreement between PSCo and all but one of the intervenors was executed and filed with the CPUC, which addressed all significant issues in the rate case. In summary, the settlement agreement, among other things, provides for:

• annual base rate decreases of approximately $33 million for natural gas and $230,000 for electricity, including an annual reduction to electric depreciation expense of approximately $20 million, effective July 1, 2003;

• an interim adjustment clause (IAC) that recovers 100 percent of prudently incurred 2003 electric fuel and purchased energy expense above the expense recovered through electric base rates during 2003. This clause is projected to recover energy costs totaling approximately $216 million in 2003;

• a new electric commodity adjustment clause (ECA) for 2004-2006, with an $11.25-million cap on any cost sharing over or under an allowed ECA formula rate; and

• an authorized return on equity of 10.75 percent for electric operations and 11.0 percent for natural gas and thermal energy operations.

In June 2003, the CPUC issued its initial written order approving the settlement agreement. The new rates were effective July 1, 2003. PSCo will now move to the phase II, rate design, portion of the case.

PSCo Fuel Adjustment Clause Proceedings - Certain wholesale electric sales customers of PSCo have filed complaints with the FERC alleging PSCo has been improperly collecting certain fuel and purchased energy costs through the wholesale fuel cost adjustment clause included in their rates. The FERC consolidated these complaints and set them for hearing and settlement judge procedures. In November 2002, the Chief Judge terminated settlement procedures after settlement was not reached. The complainants filed initial testimony in late April 2003 claiming the improper inclusion of fuel and purchased energy costs in the range of $40 million to $50 million related to the periods 1996 through 2002. PSCo submitted answer testimony in June 2003. The complainants filed rebuttal testimony on Aug. 1, 2003, and current claims have been reduced, now estimated at approximately $30 million. PSCo believes its wholesale customers have not been improperly charged for these costs. The hearings at the FERC are scheduled to begin Aug. 14, 2003.

PSCo had a retail incentive cost adjustment (ICA) cost recovery mechanism in place for periods prior to calendar 2003, as disclosed in the 2002 Annual Report on Form 10-K. The CPUC conducted a proceeding to review and approve the incurred and recoverable 2001 costs under the ICA. In April 2003, the CPUC Staff and an intervenor filed testimony recommending disallowance of certain fuel and purchased energy costs, which, if granted, would result in a $30 million reduction in recoverable 2001 ICA costs. On July 10, 2003, a stipulation and settlement agreement was filed with the CPUC, which resolved all issues. Under the stipulation and settlement agreement, the recoverable costs for 2001 will be reduced by $1.6 million. The resulting impact on the reset of the allowed cost recovery and cost sharing under the ICA for 2002 was not significant. In addition, the stipulation and settlement agreement provides for a prospective rate design adjustment related to the maximum allowable natural gas hedging costs that will be a part of the electric commodity adjustment for 2004. Approval of the 2002 recoverable ICA costs will be conducted in a future proceeding.

At June 30, 2003, PSCo has recorded its deferred fuel and purchased energy costs based on the expected rate recovery of its costs as filed in the above rate proceedings, without the adjustments proposed by various parties. Pending the outcome of these regulatory proceedings, we cannot at this time determine whether any customer refunds or disallowances of PSCo’s deferred costs will be required other than as discussed above.

PSCo Electric Department Earnings Test Proceedings – PSCo has filed its annual electric department earnings test reports for calendar 2001 and 2002. In both years, PSCo did not earn above its allowed authorized return on equity and, accordingly, has not recorded any refund obligations. In the 2001 proceeding, the Office of Consumer Counsel has proposed that the $10.9 million gain on the sale of the Boulder Hydroelectric Project be excluded from 2001 earnings and that possible refund of the gain be addressed in a separate proceeding. A final decision on both proceedings is pending.

PSCo Gas Cost Prudence Review – As previously reported, 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 before an administrative law judge in July 2002. On Feb. 10, 2003, the judge issued a recommended decision rejecting the proposed disallowances and approving PSCo's gas costs for the subject gas purchase year as prudently incurred. On June 6, 2003, the CPUC issued its order denying exceptions to the administrative law judge’s recommended decision. The CPUC upheld the finding that PSCo was prudent and reasonable in its handling of the Western Natural Gas default in January 2001.

PSCo Wholesale General Rate Case – On June 19, 2003, PSCo filed a wholesale electric rate case with the FERC, proposing to increase the annual electric sales rates charged to wholesale customers, other than Cheyenne Light Fuel & Power Co., a wholly owned subsidiary of Xcel Energy, by approximately $9 million. Several wholesale customers intervened protesting the proposed increase. On Aug. 1, 2003, PSCo submitted a revised filing correcting an error in the calculation of income tax costs. The revised filing requests an approximately $2 million annual increase with new rates effective in January 2004, subject to refund.

Home Builders Association of Metropolitan Denver (PSCo) – In February 2001, Home Builders Association of Metropolitan Denver (HBA) sought an award in the amount of $13.6 million for PSCo’s failure to update its extension policy construction allowances from 1996 to 2002 under its tariff. An administrative law judge had ruled in January 2002 that HBA’s claims were barred. The CPUC reversed that decision and remanded the case. On May 15, 2003, an administrative law judge issued a recommended decision. On the remanded issues, the judge determined the HBA is able to seek an award of reparations on behalf of its member homebuilders. However, the judge further determined the construction allowance applied by PSCo from 1996 through 2002 was neither excessive nor discriminatory, and that HBA failed to meet its burden to show that its method of calculating reparations for the period 1996 through 2002 is proper.

SPS Texas Fuel Reconciliation, Fuel Factor and Fuel Surcharge Applications - In June 2002, SPS filed an application for the Public Utility Commission of Texas (PUCT) to retrospectively review the operations of the utility’s electric generation and fuel management activities. In this application, SPS filed its reconciliation for electric generation and fuel management activities, totaling approximately $608 million, from January 2000 through December 2001. In May 2003, a stipulation was approved by the PUCT. The stipulation resolves all issues regarding SPS’ fuel costs and wholesale trading activities through December 2001. SPS will withdraw, without prejudice, its request to share in 10 percent of margins from certain wholesale non-firm sales. SPS will recover $1.1 million from Texas customers for the proposed sharing of wholesale non-firm sales

margins. The parties agreed that SPS would reduce its December 2001 fuel under-recovery balances by $5.8 million. Including the withdrawal of proposed margin sharing of wholesale non-firm sales, the net impact to SPS’ deferred fuel expense, before tax, is a reduction of $4.7 million.

In May 2003, SPS proposed to increase its voltage-level fuel factors to reflect increased fuel costs since the time SPS’ current fuel factors were approved in March 2002. The proposed fuel factors are expected to increase Texas annual retail revenues by approximately $60.2 million.

SPS also reported to the PUCT that it has under-collected its fuel costs under the current Texas retail fixed fuel factors. In the same May 2003 application, SPS proposed to surcharge $13.2 million and related interest for fuel cost under-recoveries incurred through March 2003. In June 2003, the Administrative Law Judge approved the increased fuel factors on an interim basis subject to hearings and completion of the case. The increased fuel factors became effective in July 2003. In July 2003, a unanimous settlement was reached adopting the surcharge and providing for the implementation of an expedited procedure for revising the fixed fuel factors on a semi-annual basis. The surcharge will be collected from customers over an eight-month period. In August 2003, the PUCT approved the settlement and the new proposed fuel cost recovery process and the surcharge will become effective in September 2003.

In July 2003, SPS filed a second fuel cost surcharge factor application in Texas to recover an additional $26 million of fuel cost under-recoveries accrued during April through June 2003. SPS proposed to surcharge its retail customers in Texas over a 12-month period. This new surcharge case is pending before the Texas State Office of Administrative Hearings.

SPS New Mexico Fuel Reconciliation and Fuel Factor Applications — On May 27, 2003 a hearing examiner issued a recommended decision on SPS’s fuel proceeding approving SPS utilizing a monthly fuel factor. SPS had been utilizing an annual fuel factor, which had allowed significant under-collections. The decision denied the intervenors’ request that all margins from off-system sales be credited to ratepayers. SPS will be obligated to file its next New Mexico fuel case two years after the recommended decision is approved. The recommended decision is subject to approval by the New Mexico Public Regulatory Commission (NMPRC).

TRANSLink Transmission Co., LLC (TRANSLink) – In June 2003, the MPUC held a joint hearing on the TRANSLink application, filed in December 2002. At the hearing, the MPUC deferred any decision. Instead, the MPUC indicated NSP-Minnesota could submit a supplemental or revised application to explain certain recent changes to the proposal and to respond to a number of issues and questions posed by the MPUC advisory staff. No MPUC order will be issued, and no decision has been made regarding when the revised NSP-Minnesota filing will be submitted to the MPUC.

In 2002, SPS filed for PUCT and NMPRC approval to transfer functional control of its electric transmission system to TRANSLink, of which SPS would be a participant. In March 2003, the Southwest Power Pool and the MISO cancelled their planned merger to form a large mid-continent regional transmission organization (RTO). This development materially impacted SPS’ applications in Texas and New Mexico. SPS has withdrawn its applications in those two states while it evaluates new RTO arrangements.

Xcel Energy is considering these developments, as well as the proceedings in process in other jurisdictions, to evaluate the possible future role of TRANSLink in providing transmission service in the Xcel Energy system.

FERC — California Market Manipulation - The FERC has an ongoing investigation of potential manipulation of electric and natural gas prices, which involves hundreds of parties (including NRG affiliate, West Coast Power) and substantial discovery. In June, 2001, the FERC initiated proceedings related to California’s demand for $8.9 billion in refunds from power sellers who allegedly inflated wholesale prices during the energy crisis. Hearings have been conducted before an administrative law judge who issued an opinion in late 2002. The administrative law judge stated that after assessing a refund of $1.8 billion for “unjust and unreasonable” power prices between Oct. 2, 2000 and June 20, 2001, power suppliers were owed $1.2 billion because the state of California was holding funds owed to suppliers.

In August 2002, the 9th United States Circuit Court of Appeals granted a request by the Electricity Oversight Board, the California Public Utilities Commission, and others, to seek out and introduce to the FERC additional evidence of market manipulation by wholesale sellers. This decision resulted in the FERC ordering an additional 100 days of discovery in the

refund proceeding, and also allowing the relevant time period for potential refund liability to extend back an additional nine months, to Jan. 1, 2000.

On Dec. 12, 2002, the FERC Administrative Law Judge Birchman issued a certification of proposed findings on California refund liability in docket number EL00-95-045 et al., which determined the method for calculating the mitigated energy market clearing price during each hour of the refund period. On March 26, 2003, the FERC issued an order on proposed findings on refund liability in docket number EL00-95-045 (Refund Order), adopting, in part, and modifying, in part, the proposed findings issued by Judge Birchman on Dec. 12, 2002. In the refund order, the FERC adopted the refund methodology in the staff final report on price manipulation in western markets issued contemporaneously with the refund order in docket number PA02-2-000. This refund calculation methodology makes certain changes to Judge Birchman’s methodology, because of the FERC staff’s findings of manipulation in gas index prices. This could materially increase the estimated refund liability. The refund order directed generators wanting to recover any fuel costs above the mitigated market clearing price during the refund period to submit cost information justifying such recovery within 40 days of the issuance of the refund order. West Coast Power has submitted such cost information. The FERC announced in the refund order that it expects that refunds will be paid by suppliers by the end of summer 2003.

8. 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.

NSP-Minnesota Notice of Violation- On Dec. 10, 2001, the Minnesota Pollution Control Agency (MPCA) issued a notice of violation to NSP-Minnesota alleging air quality violations related to the replacement of a coal conveyor and violations of an opacity limitation at the A.S. King generating plant. The MPCA based its notice of violation in part on an environmental protection agency (EPA) determination that the replacement constituted reconstruction of an affected facility under the Clean Air Act’s New Source Review requirements. On June 27, 2003, the EPA rejected NSP-Minnesota’s request for reconsideration of that determination. The New Source Performance Standard for coal handling systems is unlikely to require the installation of any emission controls not currently in place on the plant. It may impose additional monitoring requirements that would not have material impact on NSP-Minnesota or its operations. In addition, the MPCA or EPA may impose civil penalties for violations of up to $27,500 per day per violation. NSP-Minnesota is working with the MPCA to resolve the notice of violation.

French Island (NSP-Wisconsin) — In June 2003, the Department of Justice lodged a consent decree settling the EPA’s claims against NSP-Wisconsin related to the French Island generating plant. The consent decree will become enforceable and, unless changed in response to comments received, NSP-Wisconsin will pay a penalty of $500,000. On Aug. 2, 2003, the comment period for the consent decree expired.

Other Environmental Contingencies - 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, the subsidiary involved is pursuing or intends to pursue insurance claims and believe they will recover some portion of these costs through such claims. Additionally, where applicable, the subsidiary involved 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 in its consolidated financial statements.

Commodity Futures Trading Commission Investigation - On June 17, 2002, the Commodity Futures Trading Commission (CFTC) issued broad subpoenas to Xcel Energy on behalf of its affiliates, including NRG, calling for production, among other things, of “all documents related to natural gas and electricity trading” (June 2002, subpoenas). Since that time, Xcel Energy has produced documents and other materials in response to numerous more specific requests under the June 2002, subpoenas. Certain of these requests and Xcel Energy’s responses have concerned so-called “round-trip trades.” By a subpoena dated Jan. 29, 2003, and related letter requests (Jan. 2003, subpoena), the CFTC has requested that Xcel Energy produce all documents related to all data submittals and documents provided to energy industry publications. Also beginning on Jan. 29, 2003, the CFTC has sought testimony from 20 current and former employees and executives, and may seek additional testimony from other employees, concerning the reporting of energy transactions to industry publications. Xcel Energy has produced documents and other materials in response to the Jan. 2003, subpoena, including documents identifying instances where Xcel Energy’s e prime subsidiary reported natural gas transactions to an industry publication in a manner inconsistent with the publication’s instructions.

In June 2003, as a result of Xcel Energy’s ongoing investigation of this matter, representatives of Xcel Energy met with representatives of the CFTC and the Office of the United States Attorney for the District of Colorado. Xcel Energy has determined that e prime employees reported inaccurate trading information to one industry publication and may have reported inaccurate trading information to other industry publications. e prime ceased reporting to publications in 2002.

A number of energy companies have stated in documents filed with the FERC that employees reported fictitious natural gas transactions to industry publications. Several companies have agreed to pay between $3 million and $20 million to the CFTC to settle alleged violations related to the reporting of fictitious transactions. These and other energy companies are also subject to a recent order by the FERC placing requirements on natural gas marketers related to reporting, as well as a FERC policy statement regarding reporting of price indices. In addition, two individual traders from the companies that have been fined have been charged in criminal indictments with reporting fictitious transactions.

Xcel Energy continues to investigate this matter, and e prime has suspended and terminated several employees in connection with the reporting of inaccurate natural gas transactions to industry publications. Nevertheless, Xcel Energy believes that none of e prime’s reporting to industry publications had any effect on the financial accounting treatment of any transaction recorded in Xcel Energy’s books and records. However, Xcel Energy is unable to determine if any reporting of inaccurate trade information to industry publications affected price indices. Xcel Energy is cooperating in the CFTC investigation, but cannot predict the outcome of any investigation.

California Litigation- As discussed previously (including a discussion in the Form 10-K for the period ending December 31, 2002), California District Court Judge Robert H. Whaley dismissed both California lawsuits (State of California v. Dynegy, et al. and Public Utility District No. 1 of Snohomish County v. Xcel Energy, et al.) that named several power generators and power traders, including Xcel Energy, as defendants in multi-district litigation. In both lawsuits it was alleged that defendants engaged in unfair competition, market manipulation and price fixing. Both lawsuits were dismissed based on a finding that the filed rate doctrine precluded federal jurisdiction. These decisions have been appealed to the Ninth Circuit, which has scheduled oral arguments for later this year. Two separate class action lawsuits were also filed in Washington (Symonds v. Xcel Energy, et al.) and Oregon (Lodewick v. Xcel Energy, et al.) alleging unfair competition similar to those filed in California. Both lawsuits named Xcel Energy and NRG as defendants and have been voluntarily dismissed by the plaintiffs.

St. Cloud Gas Explosion - As discussed previously in the Form 10-K for the period ending Dec. 31, 2002, 25 lawsuits have been filed as a result of a Dec. 11, 1998 gas explosion that killed four persons (including two employees of NSP-Minnesota), injured several others and damaged numerous buildings. Most of the lawsuits name as defendants, NSP-Minnesota, Seren, Cable Constructors, Inc. (CCI) (the contractor that struck the marked gas line) and Sirti, an architectural/engineering firm hired by Seren for its St. Cloud cable installation project. Recently, the court granted the plaintiffs’ request to amend the complaint to seek punitive damages against Seren and CCI. Presently, plaintiffs are bringing a similar motion against NSP-Minnesota. NSP-Minnesota maintains that this motion is without merit. Oral arguments are tentatively scheduled to be presented to the court on Sept. 12, 2003.

Other Contingencies - The circumstances set forth in Notes 16, 18 and 19 to the Consolidated Financial Statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2002, 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 that are material to Xcel Energy’s financial position:

• NRG Bankruptcy or Insolvency — Bankruptcy plan of reorganization (Notes 4 and 6 describe the current status of certain financial contingencies related to NRG);

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

• Asset Valuation — Recoverability of investment in under-performing nonregulated projects (Seren, Argentina); and

• Guarantees — See Note 9 for discussion of exposures under various guarantees.

9. Short-Term Borrowings, Long-Term Debt and Financing Instruments

Short-Term Borrowings

At June 30, 2003, Xcel Energy and its subsidiaries had approximately $745 million of short-term debt outstanding at a weighted average interest rate of 2.357 percent.

Long-Term Debt

On July 31, 2003, NSP-Minnesota redeemed $200 million of 7.875 percent Trust Originated Preferred Securities of NSP Financing I, its wholly owned subsidiary. The redemption price for each security was its $25 principal amount plus a $0.1695 unpaid distribution. NSP-Minnesota initially funded this redemption with cash on hand, availability under its credit facility and a short-term loan from the Xcel Energy holding company.

On Aug. 8, 2003, NSP-Minnesota issued $200 million of 2.875 percent first mortgage bonds due 2006 and $175 million of 4.75 percent first mortgage bonds due 2010. The debt replaced first mortgage bonds, which matured in March and April of 2003 and helped fund the redemption of $200 million of Trust Originated Preferred Securities on July 31, 2003, which was initially funded as described above.

SFAS No. 150 — In May 2003, the FASB issued SFAS No. 150 – “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (SFAS No. 150). SFAS No. 150 establishes standards for classifying and measuring as liabilities certain financial instruments that embody obligations of the issuer and have characteristics of both liabilities and equity, including:

• instruments that represent, or are indexed to, an obligation to buy back the issuer’s shares, regardless whether the instrument is settled on a net-cash or gross physical basis;

• mandatorily redeemable equity instruments;

• written options that give the counterparty the right to require the issuer to buy back shares; and

• forward contracts that require the issuer to purchase shares.

SFAS No. 150 must be applied immediately to instruments entered into or modified after May 31, 2003, and to all other instruments that exist beginning July 1, 2003. SPS has a special purpose subsidiary trust with outstanding mandatorily redeemable preferred securities of $100 million consolidated in Xcel Energy’s Consolidated Balance Sheets, which will be required to be classified as long-term debt as of July 1, 2003. NSP-Minnesota redeemed its $200 million of Trust Originated Preferred Securities on July 31, 2003, and such securities will not be affected by SFAS No. 150. Xcel Energy continues to evaluate the impact of SFAS No. 150 on other financial instruments and has not yet determined if any other effects may result from its implementation in the third quarter of 2003.

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 June 30, 2003, Xcel Energy had the following amount of guarantees and exposure under these guarantees:


(Millions of Dollars)		Total		Exposure
Subsidiary		Guarantee		under Guarantee

NRG		$	172	$	45
e prime			215		16
Other subsidiaries			50		2

	Total	$	437	$	63

Xcel Energy guarantees certain obligations for NRG’s power marketing subsidiary, relating to power marketing obligations, fuel purchasing transactions and hedging activities and for e prime, relating to trading and hedging activities. See Note 4 for the potential treatment of these guarantees in the NRG bankruptcy proceeding.

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.

In addition, Xcel Energy provides indemnity protection for bonds issued by subsidiaries. The total amount of bonds with this indemnity outstanding as of June 30, 2003, was approximately $71 million, of which $3 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.

10. Derivative Valuation and Financial Impacts

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

The impact of the components of SFAS No. 133 on Xcel Energy’s Other Comprehensive Income, included in the Consolidated Statements of Stockholders’ Equity, are detailed in the following tables:


	Three months ended June 30,

(Millions of Dollars)	2003			2002

Balance at Mar. 31	$	(32.6	)	$	59.9
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		7.8			(10.3	)
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(18.0	)		5.3
Regulatory deferral of costs to be recovered*		4.3			—
Acquisition of NRG minority interest		—			27.4

Accumulated other comprehensive income related to SFAS No. 133 - June 30	$	(38.5	)	$	82.3


	Six months ended June 30,

(Millions of Dollars)	2003			2002

Balance at Jan. 1	$	22.1		$	34.2
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		(27.9	)		14.9
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(37.0	)		5.8
Regulatory deferral of costs to be recovered*		4.3			—
Acquisition of NRG minority interest		—			27.4

Accumulated other comprehensive income related to SFAS No. 133 – June 30	$	(38.5	)	$	82.3

In accordance with SFAS No. 71 – “Accounting for the Effects of Certain Types of Regulations,” certain costs/benefits have been deferred as they will be recovered in future periods from customers.

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

Cash Flow Hedges

Xcel Energy and its subsidiaries enter into derivative instruments to manage variability of future cash flows from 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 June 30, 2003, Xcel Energy had various commodity-related contracts deemed as cash flow hedges extending through 2009. Amounts deferred in Other Comprehensive Income are recorded as the hedged purchase or sales transaction is completed and recorded in earnings. This could include the physical purchase or sale of electric energy or the use of natural gas to generate electric energy. As of June 30, 2003, Xcel Energy had net gains of $38.7 million accumulated in Other Comprehensive Income that are expected to be recognized in earnings during the next 12 months as the hedged transaction occurs. However, due to the volatility of commodities markets, the value in Other Comprehensive Income will likely change prior to its recognition in earnings.

As required by SFAS No. 133, Xcel Energy recorded gains of $0 and $0.9 million related to ineffectiveness on commodity cash flow hedges during the three months ended June 30, 2003 and 2002, respectively, and gains of $0 and $1.0 million related to ineffectiveness on commodity cash flow hedges during the six months ended June 30, 2003 and 2002, respectively.

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 June 2004 net losses from Other Comprehensive Income of approximately $2.7 million.

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

Fair Value Hedges

Xcel Energy and its subsidiaries enter into interest rate swap instruments that effectively hedge the fair value of fixed rate debt. In June 2003, Xcel Energy entered into two five-year swaps, with a $97.5 million notional value each, against Xcel Energy’s $195 million 3.40 percent senior notes due 2008. Xcel Energy entered into the swaps to obtain greater access to the lower borrowing costs normally available on floating-rate debt. These swap agreements involve the exchange of amounts based on a variable rate of six-month London Interbank Offered Rate (LIBOR) rate plus an adder rate over the life of the agreement. The differential to be paid or received as interest rates change is accrued and recognized as an adjustment of interest expense related to the debt. The fair market value of Xcel Energy’s interest rate swaps at June 30, 2003 was $1.0 million.

Derivatives Not Qualifying for Hedge Accounting

Xcel Energy and its subsidiaries have trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market basis in the Consolidated Statements of Operations. All derivative instruments are recorded at the amount of the gain or loss from the transaction within Operating Revenues on the Consolidated Statements of Operations.

Normal Purchases or Normal Sales

Xcel Energy and its utility 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 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 qualify for a normal designation.

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

Pending Accounting Changes

SFAS No. 149 - In April 2003, the FASB issued SFAS No. 149 — “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS No. 149) which amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies the discussion around initial net investment, clarifies when a derivative contains a financing component and amends the definition of an underlying to conform it to language used in FASB Interpretation No. 45. In addition, SFAS No. 149 also incorporates certain implementation issues of a derivative implementation group. The provisions of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The guidance will be applied to hedging relationships on a prospective basis. Xcel Energy and its subsidiaries are currently assessing SFAS No. 149, but do not anticipate that it will have a material impact on consolidated results of operations, cash flows or financial position.

FASB Implementation Issue No. C20 - In June 2003, for purposes of determining the applicability of the normal purchases and normal sales scope exception, the FASB issued SFAS No. 133 Implementation Issue No. C20 as supplemental guidance to SFAS No. 133 Implementation Issue No. C11. The effective date of the implementation guidance of Issue No. C20 is the first day for the first fiscal quarter beginning after July 10, 2003, which for Xcel Energy is the fourth quarter. Xcel Energy is currently in the process of reviewing and interpreting this guidance and does not currently anticipate any material adverse financial impact due to the implementation of Issue No. C20 guidance.

11. Segment Information

Xcel Energy has the following reportable segments: Regulated Electric Utility, Regulated Natural Gas Utility and its nonregulated energy business, NRG. Trading operations performed by regulated operating companies are not a reportable segment; electric trading results are included in the Regulated Electric Utility segment and natural gas trading results are presented in All Other.


		Regulated		Regulated
(Thousands of Dollars)		Electric		Natural Gas					All		Reconciling			Consolidated
		Utility		Utility		NRG			Other		Eliminations			Total

Three months ended June 30, 2003
Operating revenues from external customers		$	1,384,551	$	273,556	$	—		$	112,908	$	—		$	1,771,015
Intersegment revenues			265		2,162		—			22,151		(24,578	)		—
Equity in earnings of Unconsolidated affiliates			—		—		—			—		—			—

	Total revenues	$	1,384,816	$	275,718	$	—		$	135,059	$	(24,578	)	$	1,771,015

Segment net income (loss)		$	69,526	$	3,762	$	(351,192	)	$	10,144	$	(14,802	)	$	(282,562	)

Three months ended June 30, 2002
Operating revenues from external customers		$	1,326,433	$	235,311	$	555,181		$	80,728	$	—		$	2,197,653
Intersegment revenues			242		324		—			44,661		(44,661	)		566
Equity in earnings of Unconsolidated affiliates			—		—		27,528			—		—			27,528

	Total revenues	$	1,326,675	$	235,635	$	582,709		$	125,389	$	(44,661	)	$	2,225,747

Segment net income (loss)		$	121,701	$	10,742	$	(41,352	)	$	2,642	$	(6,431	)	$	87,302


		Regulated		Regulated
		Electric		Natural Gas					All		Reconciling			Consolidated
		Utility		Utility		NRG			Other		Eliminations			Total

Six months ended June 30, 2003
Operating revenues from external customers		$	2,752,488	$	939,685	$	—		$	225,424	$	—		$	3,917,597
Intersegment revenues			561		3,548		—			43,931		(48,040	)		—
Equity in earnings of unconsolidated affiliates			—		—		—			—		—			—

	Total revenues	$	2,753,049	$	943,233	$	—		$	269,355	$	(48,040	)	$	3,917,597

Segment net income (loss)		$	155,624	$	60,313	$	(363,825	)	$	30,231	$	(24,893	)	$	(142,550	)

Six months ended June 30, 2002
Operating revenues from external customers		$	2,560,905	$	798,790		1,023,280		$	168,091	$	—		$	4,551,066
Intersegment revenues			501		756		—			80,286		(80,286	)		1,257
Equity in earnings of unconsolidated affiliates			—		—		42,198			—		—			42,198

	Total revenues	$	2,561,406	$	799,546	$	1,065,478		$	248,377	$	(80,286	)	$	4,594,521

Segment net income (loss)		$	203,619	$	58,795	$	(67,815	)	$	9,838	$	(13,631	)	$	190,806

In 2003, the process to allocate common costs of the Electric and Natural Gas Utility segments was revised. Segment results for 2002 have been restated to reflect the revised cost allocation process.

12. Detail of Interest and Other Income

Interest and other income, net of nonoperating expenses, is comprised of the following:


		3 months ended						6 months ended
		June 30,						June 30,

		2003			2002*			2003			2002*

Interest income		$	6,157		$	1,523		$	11,811		$	19,498
Equity income (loss) in unconsolidated affiliates (other than NRG)			1,355			1,162			(4,142	)		2,972
Other nonoperating income			9,993			12,100			13,250			21,542
Minority interest expense (other than NRG)			(582	)		(338	)		(829	)		(1,662	)
Other nonoperating expenses			(6,059	)		(2,279	)		(10,990	)		(8,351	)

	Total interest and other income, net of nonoperating expenses	$	10,864		$	12,168		$	9,100		$	33,999

Includes NRG activity.

13. Stock Compensation and Incentive Stock Awards

Restricted Stock Units – On March 28, 2003, the compensation and nominating committee of Xcel Energy’s board of directors granted restricted stock units and performance shares under the Xcel Energy omnibus incentive plan approved by the shareholders in 2000. No stock options have been granted in 2003. Restrictions on the restricted stock units will lapse after one year from the date of grant, the achievement of a 27 percent total shareholder return (TSR) for 10 consecutive business days and other criteria relating to Xcel Energy’s common equity ratio. If the TSR target is not met within four years, the grant will be forfeited. TSR is measured using the market price per share of Xcel Energy common stock, which at the grant date was $12.93, plus common dividends declared after grant date. During the second quarter of 2003, Xcel Energy accrued approximately $9 million of estimated compensation expense related to the 2.4 million restricted stock units awarded in 2003, based on an expectation that the TSR requirements will be met.

SFAS No. 148 – In December 2002, the Financial Accounting Standards Board (FASB) issued SFAS No. 148 – “Accounting for Stock-Based Compensation – Transition and Disclosure,” amending SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair-value-based method of accounting for stock-based employee compensation, and requiring disclosure in both annual and interim Consolidated Financial Statements about the method used and the effect of the method used on results. The pro-forma impact of applying SFAS 148 to earnings and earnings per share is immaterial. Xcel Energy continues to account for its stock-based compensation plans under Accounting Principles Board (APB) Opinion No. 25 – “Accounting for Stock Issued to Employees,” and does not plan at this time to adopt the voluntary provisions of SFAS No. 148. Even with full dilutive effects of stock equivalents, the impact of application of SFAS No. 148 would be immaterial to the financial results of Xcel Energy.

14. Nuclear Fuel Storage – Prairie Island Legislation

On May 29, 2003, the Minnesota Legislature enacted legislation, which will enable NSP-Minnesota to store at least 12 more casks of spent fuel outside the Prairie Island nuclear generating plant, allowing NSP-Minnesota to continue to operate the facility and store spent-fuel there until our licenses with the Nuclear Regulatory Commission (NRC) expire in 2013 and 2014. The legislation transfers from the state Legislature to the MPUC the primary authority concerning future spent-fuel storage issues and allows for additional storage of spent nuclear fuel in the event the NRC extends the licenses of the Prairie Island and Monticello nuclear generating plant and the MPUC grants a certificate of need for such additional storage without an affirmative vote from the state Legislature. The legislation requires Xcel Energy to add at least 300 megawatts of additional wind power by 2010 with an option to own 100 megawatts of this power.

The legislation also requires specified levels of payments to various third parties during the remaining operating life of the Prairie Island plant. These payments include: $2.25 million per year to the Prairie Island Tribal Community beginning in 2004; 5 percent of NSP-Minnesota’s conservation program expenditures (estimated at $2 million per year) to the University of Minnesota for renewable energy research; and an increase in funding commitments to the previously-established Renewable Development Fund from $500,000 per installed cask per year to a total of $16 million per year beginning in 2003. The legislation also designated $10 million in one-time grants to the University of Minnesota for additional renewable energy research, which is to be funded from commitments already made to the Renewable Development Fund. Nearly all of the cost increases to NSP-Minnesota from these required payments and funding commitments are expected to be recoverable in customer rates, mainly through existing cost recovery mechanisms. Funding commitments to the Renewable Development Fund would terminate after the Prairie Island plant discontinues operation unless the MPUC determines that Xcel Energy failed

to make a good faith effort to move the waste, in which case NSP-Minnesota would have to make payments in the amount of $7.5 million per year.

15. Pension Plan Change and Impacts

In April 2003, Xcel Energy amended certain of its retirement plans to provide the same level of benefits to all non-bargaining employees of its utility and service company operations. While this change did not have a material impact on 2003 costs for the affected pension and retiree health plans, the increased obligations resulting from the plan amendment did create a minimum pension liability which was recorded in the second quarter of 2003. This additional pension obligation, recorded almost entirely at SPS, increased noncurrent liabilities by approximately $21 million and reduced Accumulated Other Comprehensive Income, a component of shareholders’ equity, by approximately $25 million (net of related deferred tax effects of $14 million) during the quarter. The minimum pension liability adjustments also increased noncurrent intangible assets by approximately $41 million due to the recording of unamortized prior service costs, and reduced previously recorded prepaid pension assets accordingly.

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 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;

• the financial condition of NRG;

• actions by the bankruptcy court;

• failure to realize expectations regarding the NRG settlement agreement;

• currency translation and transaction adjustments;

• 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 Form 10-Q for the quarter ended June 30, 2003.

RESULTS OF OPERATIONS

Xcel Energy owns or has an interest in a number of nonregulated businesses, the largest of which is NRG Energy, Inc. (NRG), an independent power producer. NRG is facing severe financial difficulties and has filed a voluntary petition for bankruptcy.

See Notes 2, 3, 4 and 7 to the Consolidated Financial Statements, included in Xcel Energy’s Form 10-K for the year ended Dec. 31, 2002, and Note 4 to the Consolidated Financial Statements in this report.

Earnings Per Share Summary

The following table summarizes the earnings-per-share contributions of Xcel Energy’s businesses on both a generally accepted accounting principles (GAAP) view and a pro-forma basis. Xcel Energy is presenting pro-forma earnings to reflect its operating results excluding businesses that were or are expected to be divested this year, as assumed in the previously disclosed earnings guidance. The pro-forma results exclude the gain on the sale of Viking Gas Transmission Co. and the results of NRG. Viking Gas was sold in January 2003, and we expect the outcome of NRG’s financial restructuring will be the divestiture of NRG. The pro-forma results are provided to reflect the ongoing operations of Xcel Energy on a comparative basis for 2003 and 2002.


			3 months ended						6 months ended
			June 30,						June 30,

GAAP Earnings (Loss) by Segment:			2003			2002			2003			2002

Electric utility segment earnings			$	0.18		$	0.33		$	0.39		$	0.55
Natural gas utility segment earnings – continuing operations				0.01			0.02			0.15			0.16
Other utility segment results*				0.01			—			0.02			0.02

		Total utility segment earnings – continuing operations		0.20			0.35			0.56			0.73
Utility earnings – discontinued operations (gain from Viking Gas sale)*				—			—			0.05			—

		Total earnings from utility segments		0.20			0.35			0.61			0.73

NRG Earnings (Loss) – Continuing Operations				(0.88	)		(0.09	)		(0.91	)		(0.18	)
NRG Earnings (Loss) – Discontinued Operations				—			—			—			0.03

		Total loss from NRG segment		(0.88	)		(0.09	)		(0.91	)		(0.15	)

Other Nonregulated Results/Holding Co. Costs*				(0.03	)		(0.03	)		(0.06	)		(0.06	)

	Total GAAP Earnings (Loss) Per Share – Diluted		$	(0.71	)	$	0.23		$	(0.36	)	$	0.52

*Reconciliation of Pro-Forma Results to GAAP Earnings (Loss):*
Total utility segment earnings – continuing operations:			$	0.20		$	0.35		$	0.56		$	0.73
Other nonregulated results/holding company costs				(0.03	)		(0.03	)		(0.06	)		(0.06	)

		Pro-forma continuing operations, excluding NRG		0.17			0.32			0.50			0.67
Total NRG segment loss				(0.88	)		(0.09	)		(0.91	)		(0.15	)
Utility earnings – discontinued operations (gain on Viking Gas)				—			—			0.05			—

		Total GAAP Earnings (Loss) per Share — Diluted	$	(0.71	)	$	0.23		$	(0.36	)	$	0.52

Not a reportable segment. Included in All Other segment results in Note 11 to the financial statements.

Common Stock Dilution – Dilution from stock issued in 2002 reduced the loss for the quarter ended June 30, 2003 by 4 cents per share. For the six months ended June 30, 2003, dilution reduced the loss by 3 cents per share.

Utility Segment Results

In the second quarter of 2003, net income from utility operations decreased largely due to adverse weather impacts, higher purchased capacity costs, increased interest costs and higher incentive and other employee benefit costs. Partially offsetting these decreases were the effects of electric utility retail sales growth. For the six months ended June 30, 2003, net income from continuing utility operations decreased largely due to the second quarter impacts discussed above, partially offset by additional sales growth and short-term wholesale margins experienced in the first quarter of 2003. See the following section for additional discussion of specific margin and cost items affecting utility operating results.

Utility earnings per share were also reduced by 1 cent per share in second quarter 2003 and by 5 cents for the six months ended June 30, 2003, due to the dilutive effects of stock issuances, as discussed previously.

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


	Earnings per Share Increase (Decrease)

	2003 vs. Normal			2002 vs. Normal		2003 vs. 2002

3 months ended June 30	$	(0.02	)	$	0.03	$	(0.05	)
6 months ended June 30	$	(0.02	)	$	0.02	$	(0.04	)

Other utility segment results included in the earnings contribution table above relate to subsidiary operations of the utility companies, and to other nonregulated activities conducted by such companies, in addition to Regulated Electric and Regulated Natural Gas utility operations. The largest of these other utility businesses is PSR Investments, a subsidiary of PSCo that owns and manages life insurance policies for PSCo employees and retirees.

Also the utility earnings-per-share contribution in the table above includes income from discontinued operations related to the sale of Viking Gas in January 2003, as discussed in Note 3 to the financial statements.

NRG Segment Results

As discussed in Note 5 to the Financial Statements, as a result of NRG’s bankruptcy filing in May 2003, the presentation of NRG results is not comparable in the accompanying financial statements. NRG’s results for 2003 are presented under the equity method, on a single line, Equity in Losses of NRG. Results for 2002 are presented in the Statement of Operations with NRG consolidated as part of Xcel Energy. However, pro-forma results for 2002 are presented in Exhibit 99.02 of this report to provide 2002 information for NRG’s results on a basis comparable with the 2003 presentation.

NRG’s results summarized on an overall basis are as follows:


		3 months ended			6 months ended
(in millions)		June 30, 2003			June 30, 2003

Total NRG loss*		$	(608	)	$	(621	)
Losses not recorded by Xcel Energy under the equity method**			257			257

	Equity in losses of NRG included in Xcel Energy results	$	(351	)	$	(364	)

*		Includes discontinued operations related to several projects that have been sold or are pending sale by NRG. For 2003 reporting, no distinction is made under the equity method for the underlying NRG projects, whether discontinued or continuing.

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

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

NRG’s results in 2002 include restructuring costs and asset impairments, reported as Special Charges in Operating Expenses, as discussed in Note 2. NRG’s results in 2003 (before limitations under the equity method) include restructuring costs of $20 million for the quarter and $41 million for the six months ended June 30. Restructuring costs relate to financial and legal advisors, employee severance and other activities related to NRG’s financial restructuring and bankruptcy process.

NRG’s asset impairments and related charges in 2003 include approximately $40 million in first-quarter charges related to NRG’s NEO landfill gas projects and equity investments, and approximately $500 million recorded in the second quarter. The impairment and related charges in the second quarter of 2003 resulted from planned disposals of the Loy Yang project in Australia and the McClain and Brazos Valley projects in the United States and to regulatory developments and changing circumstances throughout the second quarter that adversely affected NRG’s ability to recover the carrying value of certain Connecticut merchant generation units. As of the bankruptcy filing date (May 14, 2003), Xcel Energy had recognized $263 million of NRG’s impairments and related charges for the Connecticut facilities and Brazos Valley as these charges were recorded by NRG prior to May 14, 2003. Consequently, Xcel Energy has recorded its equity in NRG results for the second quarter (including these impairments) in excess of its financial commitment to NRG under the settlement agreement. These excess losses of $115 million will be reversed and recognized as a non-cash gain upon NRG’s emergence from bankruptcy. See Note 5 to the financial statements for further discussion of the 2003 change in accounting for NRG and Xcel Energy’s limitation for recognizing NRG’s losses due to its bankruptcy filing.

In addition to the unusual items discussed above, NRG’s operating results have been affected by low wholesale power prices in North America, which have provided margins insufficient to cover its interest and other fixed costs, and have resulted in continuing operating losses in 2003.

Beginning in the third quarter of 2002, Xcel Energy announced that the likely tax filing status of NRG for 2002 and future years had 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 its operating losses and is currently in a net operating loss carryforward position for tax purposes. Accordingly, NRG’s results for 2003 include no material tax effects.

Other Results — Nonregulated Subsidiaries (Other than NRG) and Holding Company Costs

The following table summarizes the earnings-per-share (EPS) contributions of Xcel Energy’s nonregulated businesses other than NRG and holding company results:


	3 months ended						6 months ended
	June 30,						June 30,

	2003			2002			2003			2002

Other Nonregulated and Holding Company Results:
Seren Innovations, Inc.	$	(0.01	)	$	(0.02	)	$	(0.02	)	$	(0.03	)
Xcel International		0.01			0.00			0.02			0.00
Eloigne Company		0.00			0.00			0.01			0.01
Planergy International		(0.01	)		0.00			(0.01	)		(0.01	)
Financing Costs and Preferred Dividends		(0.03	)		(0.03	)		(0.06	)		(0.05	)
Other		0.01			0.02			0.00			0.02

Total Other Nonregulated and Holding Company	$	(0.03	)	$	(0.03	)	$	(0.06	)	$	(0.06	)

Seren – Seren operates a combination cable television, telephone and high-speed Internet access system in St. Cloud, Minn., and Contra Costa County, California. At June 30, 2003, Xcel Energy’s investment in Seren was approximately $265 million.

Xcel International – Xcel International owns and operates several energy projects in Argentina. Earnings in the second quarter of 2003 include a gain from a debt restructuring for one of the projects, which increased earnings by about 1 cent per share.

Financing Costs and Preferred Dividends - Nonregulated and holding company results include 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. Holding company financing costs increased due to the issuance of convertible debt in November 2002.

Other – Other nonregulated and holding company results decreased in 2003 due to lower income from Utility Engineering and from NRG-related restructuring costs, as discussed previously. Partially offsetting these earnings reductions were income tax adjustments related mainly to changing state tax effects resulting from NRG tax deconsolidation and losses.

Income Statement Analysis — Second Quarter 2003 vs. Second Quarter 2002

Electric Utility and Commodity Trading Margins

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel cost recovery mechanisms for retail customers in several states, most fluctuations in energy costs do not materially affect electric utility margin. The retail fuel clause cost recovery mechanism in Colorado has changed from 2002 to 2003. For 2002, electric utility margins in Colorado reflect the impact of sharing energy costs and savings relative to a target cost per delivered kilowatt-hour under the retail incentive cost adjustment (ICA) ratemaking mechanism. For 2003, PSCo will be able to collect 100 percent of its retail electric fuel and purchased energy expense through the interim adjustment clause (IAC). In addition to the IAC, Colorado has other adjustment clauses that allow certain costs to be recovered from retail customers.

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

Xcel Energy’s commodity trading operations are conducted by NSP-Minnesota (electric), PSCo (electric) and e prime (natural gas). Margins from electric trading activity, conducted at NSP-Minnesota and PSCo, are partially redistributed to other operating utilities of Xcel Energy, pursuant to a joint operating agreement (JOA) approved by the FERC. PSCo’s short-term wholesale margins and electric trading margins reflect the impact of regulatory sharing of certain margins with Colorado retail customers. Trading results are reported net of related costs (i.e., on a margin basis) in the Consolidated Statements of Operations. Trading revenue and costs associated with NRG’s operations are included in the NRG segment results, not reflected in the table below. The following table details the revenue and margin for base electric utility, short-term wholesale and electric and natural gas trading activities.


	Base			Short-			Electric			Natural Gas
	Electric			Term			Commodity			Commodity			Intercompany			Consolidated
(Millions of Dollars)	Utility			Wholesale			Trading			Trading			Eliminations			Total

Three months ended June 30, 2003
Electric utility revenue	$	1,340		$	39		$	—		$	—		$	—		$	1,379
Electric fuel and purchased power		(610	)		(31	)		—			—			—			(641	)
Electric and natural gas trading revenue		—			—			75			80			(8	)		147
Electric and natural gas trading costs		—			—			(69	)		(82	)		8			(143	)

Gross margin before operating expenses	$	730		$	8		$	6		$	(2	)	$	—		$	742

Margin as a percentage of revenue		54.5	%		20.5	%		8.0	%		(2.5	)%		—	%		48.6	%

Three months ended June 30, 2002
Electric utility revenue	$	1,289		$	40		$	—		$	—		$	—		$	1,329
Electric fuel and purchased power		(514	)		(30	)		—			—			—			(544	)
Electric and natural gas trading revenue		—			—			494			566			(20	)		1,040
Electric and natural gas trading costs		—			—			(496	)		(564	)		20			(1,040	)

Gross margin before operating expenses	$	775		$	10		$	(2	)	$	2		$	—		$	785

Margin as a percentage of revenue		60.1	%		25.0	%		(0.4	)%		0.4	%		—	%		33.1	%

Base electric utility margins, primarily related to retail customers, decreased approximately $45 million for the second quarter of 2003, compared with the second quarter of 2002. The lower base electric utility margin reflects much cooler temperatures in the second quarter of 2003 compared with 2002, higher purchased capacity costs and the positive impact of incentive cost adjustment mechanisms in 2002, partially offset by weather-normalized sales growth and recovery of renewable development fund costs in 2003 for which a corresponding charge to depreciation expense was recorded.

Short-term wholesale margins consist of asset-based electric sales for resale activity. Electric and natural gas commodity trading activity margins consist of non-asset-based trading activity. Short-term wholesale and electric commodity trading sales margins increased approximately $6 million for second quarter 2003 due mainly to more favorable market prices.

Natural Gas Utility Margins

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


	Three Months Ended June 30,

(Millions of Dollars)	2003			2002

Natural gas utility revenue	$	274		$	236
Cost of natural gas sold and transported		(175	)		(126	)

Natural gas utility margin	$	99		$	110

Natural gas revenue increased by approximately $38 million, or 16.1 percent, in the second quarter of 2003, primarily due to increases in the wholesale cost of natural gas, which are largely passed on to customers and recovered through various rate adjustment clauses in most of the jurisdictions in which Xcel Energy operates. Natural gas margin decreased by approximately $11 million, primarily due to warmer-than-normal weather and a decline in interruptible and transportation sales.

Nonregulated Margins (Other than NRG)

The following table details the change in nonregulated revenue and margin, excluding NRG’s operations.


		Three Months Ended June 30,

(Millions of Dollars)		2003			2002

Nonregulated and other revenue		$	115		$	79
Nonregulated cost of goods sold			(70	)		(55	)

	Nonregulated margin	$	45		$	24

Nonregulated revenues and margins for the second quarter increased in 2003 compared to 2002 due mainly to increasing customer levels in Seren’s communication business, higher contract revenues in Xcel International’s Argentina operations. These margin increases were offset by higher operating and other costs, resulting in approximately the same operating results from nonregulated companies in both periods, as indicated in the previous earnings contribution table.

Non-Fuel Operating Expense and Other Costs

Utility Other Operation and Maintenance Expenses for the second quarter of 2003 increased by approximately $38 million, or 11.0 percent, compared with the second quarter of 2002. Approximately $13 million of the difference results from the second quarter 2002 reversal of accrued estimated incentive compensation expense, compared with an accrual of estimated incentive compensation expense in the second quarter 2003. In addition, benefit costs increased $31 million due to lower pension credits, higher medical and health care costs and restricted stock units granted. Utility operating and maintenance expenses also increased due to a planned refueling outage at the Monticello nuclear plant compared with no such nuclear outages in the second quarter of 2002. These cost increases were partially offset by the timing of non-nuclear plant outages and other cost reductions.

Excluding NRG amounts in 2002, depreciation and amortization increased by approximately $16 million, or 8.2 percent, for the second quarter of 2003, compared with the second quarter of 2002, primarily due $10 million of Minnesota renewable development fund costs, which are largely recovered through NSP-Minnesota’s fuel clause mechanism, and higher depreciation from utility plant additions.

Excluding NRG amounts in 2002, interest expense increased by approximately $26 million, or 31.6 percent, for the second quarter of 2003, compared with the second quarter of 2002. This increase is due to the issuance of long- and intermediate-term debt to reduce dependence on short-term debt at the holding company, NSP-Minnesota and PSCo.

Excluding NRG amounts in 2002, income taxes changed due to changes in pretax income and to a lesser extent to changes in the effective tax rate. The effective tax rate for non-NRG operations was (19.3) percent in the second quarter of 2003 and 34.5 percent in the same quarter of 2002. The change in the effective tax rate between years reflects a larger ratio of tax credits to lower pretax income levels in 2003, adjustments to 2002 and year-to-date 2003 state tax accruals recorded in 2003 related to updated income apportionment by state (including NRG impacts) and NSP-Minnesota adjustments due to favorable income tax audit settlements in 2003.

Income Statement Analysis — First Six Months of 2003 vs. First Six Months of 2002

Electric Utility and Commodity Trading Margins

The following table details the revenue and margin for base electric utility, short-term wholesale and electric and natural gas trading activities.


				Short-			Electric			Natural Gas
	Base Electric			Term			Commodity			Commodity			Intercompany			Consolidated
(Millions of Dollars)	Utility			Wholesale			Trading			Trading			Eliminations			Total

Six months ended June 30, 2003
Electric utility revenue	$	2,647		$	101		$	—		$	—		$	—		$	2,748
Electric fuel and purchased power		(1,162	)		(72	)		—			—			—			(1,234	)
Electric and natural gas trading revenue		—			—			133			463			(21	)		575
Electric and natural gas trading costs		—			—			(129	)		(460	)		21			(568	)

Gross margin before operating expenses	$	1,485		$	29		$	4		$	3		$	—		$	1,521

Margin as a percentage of revenue		56.1	%		28.7	%		3.0	%		0.6	%		—	%		45.8	%

Six months ended June 30, 2002
Electric utility revenue	$	2,480		$	81		$	—		$	—		$	—		$	2,561
Electric fuel and purchased power		(966	)		(66	)		—			—			—			(1,032	)
Electric and natural gas trading revenue		—			—			811			1,021			(37	)		1,795
Electric and natural gas trading costs		—			—			(810	)		(1,020	)		37			(1,793	)

Gross margin before operating expenses	$	1,514		$	15		$	1		$	1		$	—		$	1,531

Margin as a percentage of revenue		61.0	%		18.5	%		0.1	%		0.1	%		—	%		35.1	%

Base electric utility margins, primarily related to retail customers, decreased approximately $29 million for the first six months of 2003 compared with the first six months of 2002. The lower base electric margin reflects much cooler temperatures in the second quarter of 2003, higher purchased capacity costs in 2003 and the positive impact of incentive cost adjustment mechanisms in 2002, partially offset by weather-normalized sales growth and recovery of renewable development fund costs in 2003 for which a corresponding charge to depreciation expense was recorded.

Short-term wholesale and electric and natural gas commodity trading sales margins increased approximately $19 million for the first six months of 2003 compared with the same period in 2002. The short-term wholesale increase reflects more favorable prices on electric sales to other utilities, primarily in Minnesota.

Natural Gas Utility Margins


	Six Months Ended June 30,

(Millions of Dollars)	2003			2002

Natural gas utility revenue	$	940		$	800
Cost of natural gas sold and transported		(655	)		(501	)

Natural gas utility margin	$	285		$	299

Natural gas revenue increased by approximately $140 million, or 17.5 percent, in the first six months of 2003 compared with the same period in 2002, primarily due to increases in the wholesale cost of natural gas, which are largely passed on to customers and recovered through various rate adjustment clauses in most of the jurisdictions in which Xcel Energy operates. Natural gas margin decreased by approximately $14 million, primarily due to the impact of warmer-than-normal weather, and the sale of Viking Gas in January 2003, partially offset by weather-normalized firm sales growth.

Nonregulated Margins (Other than NRG)

The following table details the change in nonregulated revenue and margin, excluding NRG’s operations.


		Six Months Ended June 30,

(Millions of Dollars)		2003			2002

Nonregulated and other revenue		$	223		$	167
Nonregulated cost of goods sold			(147	)		(112	)

	Nonregulated margin	$	76		$	55

Nonregulated revenues and margins for the second quarter increased in 2003 compared to 2002 due mainly to increasing customer levels in Seren’s communication business, higher contract revenues in Xcel International’s Argentina operations, and increased retail service revenues. These margin increases were offset by higher operating and other costs, resulting in approximately the same operating results by nonregulated company in both periods, as indicated in the previous earnings contribution table.

Non-Fuel Operating Expense and Other Costs

Utility Other Operation and Maintenance Expenses for the six months ended June 30, 2003, increased by approximately $28 million, or 3.8 percent, compared with the same period in 2002. The increased costs reflect the timing of incentive accruals in 2002 and higher other employee benefit costs, as discussed previously.

Excluding NRG amounts in 2002, depreciation and amortization increased by approximately $16 million, or 4.1 percent, for the first six months of 2003, compared with 2002, primarily due to $10 million of Minnesota renewable development fund costs, which are largely recovered through NSP-Minnesota’s fuel clause mechanism, and higher depreciation from utility plant additions.

Excluding NRG amounts in 2002, interest expense increased by approximately $57 million, or 35.8 percent, for the first six months of 2003, compared with 2002. This increase is due to the issuance of long-and intermediate-term debt to reduce dependence on short-term debt at the holding company, NSP-Minnesota and PSCo.

Excluding NRG amounts in 2002, income taxes changed due to a change in pretax income and to a lesser extent to changes in the effective tax rate. The effective tax rate for non-NRG operations was 20.7 percent in the first six months of 2003 and 33.9 percent in the same period of 2002. The change in the effective tax rate between years reflects a larger ratio of tax credits to the lower pretax income levels in 2003, adjustments to 2002 and 2003 state tax accruals recorded in 2003, as discussed previously, and NSP-Minnesota adjustments due to favorable tax audit settlements in 2003. The change is likely to also result in a decrease in the 2003 annual effective tax rate for Xcel Energy, excluding NRG.

Pending Accounting Changes

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

As of June 30, 2003, the assets of these entities were approximately $155 million and long-term liabilities were approximately $90 million. Currently, investments of $61 million are reflected as a component of investments in unconsolidated affiliates in the Dec. 31, 2002, Consolidated Balance Sheet. FIN No. 46 requires that for entities to be consolidated, the entities’ assets be initially recorded at their carrying amounts at the date the new requirement first applies. If determining carrying amounts as required is impractical, then the assets are to be measured at fair value as of the first date the new requirements apply. Any difference between the net consolidated amounts added to the Xcel Energy’s balance sheet and the amount of any previously recognized interest in the newly consolidated entity should be recognized in earnings as the cumulative-effect adjustment of an accounting change. Had Xcel Energy adopted FIN No. 46 requirements early in 2003, there would have been no material impact to net income. Xcel Energy plans to adopt FIN No. 46 when required in the third quarter of 2003.

See Notes 9, 10 and 13 to the consolidated financial statements for discussion of additional pending accounting changes.

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 all 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, 2002, 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.

Financial Market Risks

Xcel Energy and its subsidiaries are exposed to market risks, including changes in commodity prices and interest rates, as disclosed in Management’s Discussion and Analysis in its Annual Report on Form 10-K for the year ended Dec. 31, 2002. Commodity price and interest rate risks for Xcel Energy’s regulated subsidiaries are mitigated in most jurisdictions due to cost-based rate regulation. At June 30, 2003, there were no material changes to the financial market risks that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2002, in Item 7A of Xcel Energy’s Annual Report on Form 10-K.

NSP-Minnesota maintains trust funds, as required by the Nuclear Regulatory Commission, to fund certain costs of nuclear decommissioning. Those investments are exposed to price fluctuations in equity markets and changes in interest rates. However, because the costs of nuclear decommissioning are recovered through NSP-Minnesota rates, fluctuations in investment fair value do not affect NSP-Minnesota’s consolidated results of operations.

Xcel Energy and its subsidiaries use a value-at-risk (VaR) model to assess the market risk of their fixed price purchase and sales commitments, physical forward contracts and commodity derivative instruments. VaR for hedges associated with generating assets and commodity contracts, assuming a five-day holding period for electricity and a two-day holding period for natural gas, for the three months ended June 30, 2003, is as follows:


	Period End		Change from
(Millions of dollars)	June 30, 2003		March 31, 2003			VaR Limit		Average		High		Low

Electric Commodity
Trading (1)	$	0.90	$	0.29		$	6.0	$	0.69	$	1.00	$	0.41
e prime Inc.		0.01		(0.04	)		2.0		0.05		0.17		0.01
e prime Energy Marketing Inc.		0.07		(0.81	)		2.0		0.29		0.88		0.02
XERS Inc.		0.13		0.12			2.0		0.04		0.15		0.00

(1)

Comprises transactions for both NSP-Minnesota and PSCo.

Energy Trading and Hedging Activities

Xcel Energy and its subsidiaries engage in energy trading activities that are accounted for in accordance with SFAS No. 133, as amended. Xcel Energy makes wholesale purchases and sales of electric, natural gas and related energy trading products and provides risk management services to other of its unregulated subsidiaries in order to optimize the value of their electric generating facilities and retail supply contracts. Xcel Energy also engages in a limited number of wholesale commodity transactions. Xcel Energy utilizes forward contracts for the purchase and sale of electricity and capacity, over-the-counter swap contracts, exchange-traded natural gas futures and options, transmission contracts, natural gas transportation contracts and other physical and financial contracts.

For the period ended June 30, 2003, these contracts, with the exception of transmission and natural gas transportation contracts, were marked to market in accordance with Emerging Issues Task Force (EITF) 02-3 and SFAS No. 133. Changes in fair value of energy trading contracts that do not qualify for hedge accounting treatment are recorded in income in the reporting period in which they occur.

As of June 30, 2003, the sources of fair value of the energy trading and hedging net assets are as follows:

Trading Contracts


	Futures/Forwards

	Source of		Maturity Less			Maturity	Maturity	Maturity Greater	Total Futures/
(Thousands of Dollars)	Fair Value		Than 1 Year			1 to 3 Years	4 to 5 Years	Than 5 Years	Forwards Fair Value

NSP-Minnesota		1	$	(472	)				$	(472	)
		2		2,283						2,283
PSCo		1		(1,331	)					(1,331	)
		2		1,701						1,701
e prime Inc.		1		1,209						1,209
		2		172						172

Total Futures/Forwards
Fair Value			$	3,562					$	3,562

Options

Source of

Maturity Less

Maturity

Maturity Greater

Total Futures/

(Thousands of Dollars)

Fair Value

Than 1 Year

1 to 3 Years

4 to 5 Years

Than 5 Years

Forwards Fair Value

e prime Inc.

Total
Futures/Forwards

Fair Value

Hedge Contracts


	Futures/Forwards

	Source of		Maturity Less			Maturity			Maturity	Maturity Greater	Total Futures/
(Thousands of Dollars)	Fair Value		Than 1 Year			1 to 3 Years			4 to 5 Years	Than 5 Years	Forwards Fair Value

NSP-Minnesota		2	$	(1,760	)						$	(1,760	)
NSP-Wisconsin		2		(304	)							(304	)
PSCo		1		1,047								1,047
		2		(9,230	)							(9,230	)
e prime Inc.		1		320								320
e prime Energy Mktg. Inc.		1		5			(396	)				(391	)
XERS Inc.		1		2,576			(9	)				2,567
Total Futures/Forwards

Fair Value			$	(7,346	)	$	(405	)			$	(7,751	)


	Options

	Source of		Maturity Less			Maturity		Maturity	Maturity Greater	Total Futures/
(Thousands of Dollars)	Fair Value		Than 1 Year			1 to 3 Years		4 to 5 Years	Than 5 Years	Forwards Fair Value

NSP-Minnesota		2	$	(200	)					$	(200	)
PSCo		2		(311	)		1,980				1,669

Total Futures/Forwards
Fair Value			$	(511	)	$	1,980			$	1,469

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

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

In the above tables, only “hedge” transactions are included for NSP-Minnesota, NSP-Wisconsin and PSCo. “Normal purchases and sales” transactions have been excluded.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows


	Six Months Ended June 30,

(Millions of Dollars)	2003		2002

Net cash provided by (used in) operating activities	$	574	$	597

Cash provided by operating activities decreased for the first six months of 2003, compared with the first six months of 2002. The decrease was primarily due to lower income from operations in 2003. NRG cash flows included in 2002 amounts were not material in relation to total operating cash flows of Xcel Energy, and no NRG operating cash flows are reflected in 2003.


	Six Months Ended June 30,

(Millions of Dollars)	2003			2002

Net cash provided by (used in) investing activities	$	(354	)	$	(1,632	)

Cash used in investing activities decreased for the first six months of 2003, compared with the first six months of 2002. The decrease is largely due to lower nonregulated capital expenditures and equity investments by NRG due to its financial situation since July 2002. In addition, 2003 net cash outflows were partially offset by the proceeds from the sale of Viking Gas in January 2003.


	Six Months Ended June 30,

(Millions of Dollars)	2003			2002

Net cash provided by (used in) financing activities	$	(304	)	$	1,189

Cash flows related to financing activities decreased from net inflows for the first six months of 2002 to net outflows in the first six months of 2003. The decrease is largely due to lower financing requirements resulting from decreased capital spending by NRG.

Credit Facilities

As of July 30, 2003, Xcel Energy had the following credit facilities available to meet its liquidity needs:


(Millions of Dollars)
Company		Facility		Drawn		Available		Cash		Liquidity		Maturity

NSP-Minnesota		$	275	$	155	$	120	$	31	$	151	May-2004
NSP-Wisconsin		$	0	$	0	$	0	$	3	$	3
PSCo		$	350	$	266	$	84	$	26	$	110	May 2004
PSCo Bridge Facility		$	300	$	300	$	0	$	0	$	0	June 2004
SPS		$	100	$	38	$	62	$	28	$	90	Feb. 2004
Xcel Energy – Holding Company		$	400	$	130	$	270	$	341	$	611	Nov. 2005

	Total	$	1,425	$	889	$	536	$	429	$	965

Xcel Energy expects to accumulate additional cash at the holding company level during 2003 from the lower federal income tax payments resulting from the expected tax benefit associated with its investment in NRG and from the receipt of operating company dividends. Restrictions by state regulatory commissions, debt agreements and PUHCA over the level of dividends the utility operating companies limit the amount of dividends the utility subsidiaries can pay to Xcel Energy.

Financing Activities

Xcel Energy

In May 2003, Xcel Energy registered the resale of $230 million of 7.5 percent senior convertible notes due 2007 with the SEC. The notes had been previously sold to qualified institutional buyers.

In June 2003, Xcel Energy issued $195 million of 3.40 percent senior notes due 2008. The notes were sold to qualified institutional buyers.

NSP-Minnesota

In April 2003, NSP-Minnesota amended an existing shelf registration statement with $415 million of available debt to allow for the issuance of secured debt, in addition to unsecured debt.

On August 8, 2003, NSP-Minnesota issued $200 million of 2.875 percent first mortgage bonds due 2006 and $175 million of 4.75 percent first mortgage bonds due 2010. The debt replaced debt, which matured in March and April of 2003 and helped fund the redemption of $200 million of Trust Originated Preferred Securities on July 31, 2003, which was initially funded as described above.

PSCo

In March 2003, PSCo issued $250 million of 4.875 percent first collateral trust bonds due 2013. The bonds were sold to qualified institutional buyers.

In April 2003, PSCo registered $500 million of additional debt securities to supplement the existing $300 million of already registered debt securities.

On June 30, 2003, PSCo redeemed its $145 million of 8.75 percent first mortgage bonds due March 1, 2022. The redemption price was 100 percent of the principal amount plus a 3.76 percent call premium and accrued interest.

On June 30, 2003, PSCo’s trust subsidiary PSCo Capital Trust I redeemed its $194 million of 7.60 percent Trust Originated Preferred Securities. The redemption price for each security was its $25 principal amount plus a $0.475 unpaid distribution.

The redemptions were temporarily funded from the $300 million short-term credit facility, the $350 million revolving credit facility, and cash on hand. PSCo expects to issue permanent financing of about $575 million during the third quarter of 2003.

Short-term debt and financial instruments are discussed in Note 9 to the Financial Statements.

Financing Plans

The following details Xcel Energy’s financing plan for debt issuances during 2003, subject to favorable market conditions:

• PSCo expects to issue up to $575 million of debt for working capital and repayment of short-term borrowings incurred for the redemption of $194 million of Trust Originated Preferred Securities and $145 million of 8.75 percent first mortgage bonds. Both issues were redeemed on June 30, 2003. PSCo has entered into a bridge financing arrangement to provide short-term liquidity until it completes its long-term debt offering.

• NSP-Wisconsin expects to issue up to $150 million of debt to replace debt maturing in 2003 and for possible refinancing of existing long-term with lower coupon debt.

• SPS may issue up to $100 million of debt for refinancing of higher coupon securities.

Financing Restrictions

Registered holding companies and certain of their subsidiaries, including Xcel Energy and its utility subsidiaries, are limited, under PUHCA, in their ability to issue securities. Such registered holding companies and their subsidiaries may not issue securities unless authorized by an exemptive rule or order of the SEC. Because Xcel Energy does not qualify for any of the main exemptive rules, it sought and received financing authority from the SEC under PUHCA for various financing arrangements. Xcel Energy’s current financing authority permits it, subject to satisfaction of certain conditions, to issue through Sept. 30, 2003 up to $2 billion of common stock and long-term debt and $1.5 billion of short-term debt at the holding company level. Xcel Energy has issued $2 billion of long-term debt and common stock. Consequently, absent further authorization from the SEC under PUHCA, Xcel Energy will not be able to issue any additional common stock (other than through benefit plans or dividend reinvestment) or long-term debt. Xcel Energy has requested an extension of its financing authority to Sept. 30, 2004 and an increase in that authority to $2.5 billion of long-term debt and common stock.

Dividend Restrictions

As a result of additional write-downs at NRG, Xcel Energy’s retained earnings were a deficit of approximately $245 million on June 30, 2003. Based on current retained earnings levels and assumptions regarding third quarter earnings and the timing of recognition of tax benefits associated with Xcel Energy’s investment in NRG, it appears unlikely that Xcel Energy would have sufficient retained earnings to pay third quarter dividends without a waiver from the SEC under PUHCA.

Under the PUHCA, unless there is an order from the SEC, a holding company or any subsidiary may declare and pay dividends only out of retained earnings. In May 2003, Xcel Energy received authorization from the SEC to pay an aggregate amount of $152 million of common and preferred dividends out of capital and unearned surplus. Xcel Energy used this authorization to declare and pay approximately $150 million for its first and second quarter dividends in 2003. In addition, the SEC reserved jurisdiction, which would allow Xcel Energy to pay an additional $108 million of common and preferred dividends out of capital and unearned surplus until Sept. 30, 2003, if authorized by further action of the SEC.

Since it appears that retained earnings will be insufficient to declare and pay a third quarter dividend as normally scheduled, Xcel Energy intends to request authorization from the SEC to pay its third quarter dividend out of capital and unearned surplus. In the event that authorization is not received from the SEC to pay the third quarter dividend in that manner, and assuming that the NRG plan of reorganization is approved by NRG’s creditors in 2003 as expected, Xcel Energy currently expects to have retained earnings sufficiently positive before the end of 2003 to pay dividends from retained earnings at that time. Xcel Energy intends to make every effort to pay the full annual dividend of 75 cents per share during 2003 on its common stock and all accrued dividends on its preferred stock.

NRG Financial Issues and Bankruptcy

As discussed in Note 4 to the Consolidated Financial Statements, since mid-2002, NRG has experienced severe financial difficulties, resulting primarily from declining credit ratings and lower wholesale prices for power. These financial difficulties have caused NRG to, among other things, miss several scheduled payments of interest and principal on its bonds and incur

asset impairment charges and other costs in excess of $3 billion in 2002. These asset impairment charges related to write-offs for anticipated losses on sales of several projects as well as anticipated losses related to projects for which NRG has stopped funding. In addition, as a result of having its credit ratings downgraded, NRG is in default of obligations to post cash collateral of approximately $1 billion. Furthermore, on Nov. 6, 2002, lenders to NRG accelerated approximately $1.1 billion of NRG’s debt under the construction revolver financing facility, rendering the debt immediately due and payable. In addition, on Feb. 27, 2003, lenders to NRG accelerated approximately $1.0 billion of NRG Energy’s debt under the corporate revolver financing facility, rendering the debt immediately due and payable. On May 14, 2003, NRG, including certain subsidiaries, filed a voluntary petition for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. The filing included NRG’s plan of reorganization among Xcel Energy, NRG and various members of NRG’s major credit constituencies.

On March 26, 2003, Xcel Energy’s board of directors approved a tentative settlement with holders of most of NRG’s long-term notes and the steering committee representing NRG’s bank lenders regarding alleged claims of such creditors against Xcel Energy. Xcel Energy would pay up to $752 million to NRG to settle all claims of NRG against Xcel Energy, including all claims under a capital support agreement between Xcel Energy and NRG. The principal terms and contingencies to consummation of the settlement are discussed in Note 4.

Xcel Energy expects to finance the payments with cash on hand at the holding company level and with funds from the tax benefits associated with its write-off of its investment in NRG. See further discuss of the tax implications of the bankruptcy and settlement agreement in Notes 4 and 6. Upon the effective date of the NRG plan of reorganization, Xcel Energy’s exposure on any guarantees or other credit support obligations incurred by Xcel Energy for the benefit of NRG or any subsidiary would be terminated and any cash collateral posted by Xcel Energy would be returned to it. The current amount of such cash collateral is approximately $0.5 million.

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. In the event the settlement described above is not effectuated, Xcel Energy believes that any effort to substantively consolidate Xcel Energy with NRG would be without merit. However, it is possible that NRG or its creditors would attempt to advance such claims, or other claims under piercing the corporate veil, alter ego, control person or related theories, in the NRG bankruptcy proceeding. If a bankruptcy court were to allow substantive consolidation of Xcel Energy and NRG or if another court were to allow related claims, it would have a material adverse effect on Xcel Energy.

The accompanying Consolidated Financial Statements do not necessarily reflect future conditions or matters that may arise as a result of NRG’s bankruptcy filing and its ultimate resolution. Pending the outcome of its voluntary bankruptcy petition, NRG remains subject to substantial doubt as to its ability to continue as a going concern. See Note 5 for discussion of the change in Xcel Energy’s financial statement presentation of NRG in 2003, as a result of the bankruptcy filing. In addition, Exhibit 99.02 includes pro-forma Xcel Energy income statement information for the six months ended June 30, 2002, presenting NRG under the equity method, on a basis comparable to the year-to-date income statement for 2003 included in this report. Pro-forma financial information has not been provided for the effects on Xcel Energy of actually divesting NRG, once it emerges from bankruptcy, due to the limited nature of such effects. In relation to the deconsolidated, equity method reporting of NRG in 2003 (and the corresponding pro-forma amounts for periods prior to 2003), these divestiture effects would be limited to the payment of the settlement obligations (that is, elimination of the negative investment) and the discontinuance of recording any equity in NRG’s losses.

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

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. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the chief executive officer (CEO) and chief financial officer (CFO), of the effectiveness of our disclosure controls and procedures, except as indicated in the next paragraph, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures are effective.

During the fourth quarter of 2002, Xcel Energy’s wholly owned subsidiary, NRG, determined that there were certain deficiencies in the internal controls relating to financial reporting at NRG caused by NRG’s pending financial restructuring and business realignment. During the second half of 2002, there were material changes and vacancies in senior NRG management positions and a diversion of NRG financial and management resources to restructuring efforts. These circumstances detracted from NRG’s ability, through its internal controls, to timely monitor and accurately assess the impact of certain transactions, as would be expected in an effective financial reporting control environment. NRG has dedicated and will continue to dedicate in 2003 resources to make corrections to those control deficiencies. Notwithstanding the foregoing and as indicated in the certification accompanying the signature page to this report, the certifying officers have certified that, to the best of their knowledge, the financial statements and other financial information included in this report on Form 10-Q, fairly present in all material respects the financial condition, results of operations and cash flows of Xcel Energy as of, and for the periods presented in this report.

No change in Xcel Energy’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting. Also, subsequent to the date of the most recent evaluation, there have been no significant changes in Xcel Energy’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 7 and 8 of the Consolidated 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 2002 Form 10-K and Note 18 of the consolidated financial statements in such Form 10-K 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.

SPS

On July 24, 1995, Lamb County Electric Cooperative, Inc. (LCEC) petitioned the PUCT for a cease and desist order against SPS. LCEC alleged that SPS had been unlawfully providing service to oil field customers and their facilities in LCEC’s singly certificated area. Lamb County also has sued Xcel Energy in Texas state court. In April 2003, the PUCT approved a recommended proposal for decision. Xcel Energy defended its service by demonstrating that in 1976 the cooperatives, Xcel Energy and the PUCT intended that Xcel Energy was to serve the expanding oil field operations. Xcel Energy demonstrated through extensive research that it was serving each of the oil field units and leases back in 1975, and it was not serving new customers. The PUCT decided that Xcel Energy was authorized to serve the oil field operations and denied LCEC’s request for a cease and desist order.

NRG

Connecticut Light & Power Company v. NRG Power Marketing Inc., Docket No. 3:01-CV-2373 (A WT), pending in the United States District Court, District of Connecticut - This matter involves a claim by The Connecticut Light & Power Company (CL&P) for recovery of amounts it claims are owing for congestion charges under the terms of a standard offer services contract between the parties, dated Oct. 29, 1999. CL&P has served and filed its motion for summary judgment to which NRG Power Marketing Inc. (NRG PMI) filed a response on March 21, 2003. CL&P has offset approximately $30 million from amounts owed to NRG PMI, claiming that it has the right to offset those amounts under the contract. NRG PMI has counterclaimed seeking to recover those amounts, arguing among other things that CL&P has no rights under the contract to offset them. On May 14, 2003, NRG PMI provided notice to CL&P of termination of the contract effective May 19, 2003. Pursuant to the request of the Attorney General of Connecticut and the Connecticut Department of Public Utility Control, on May 16, 2003, the FERC issued an order directing NRG PMI to continue to provide service to CL&P under the contract,

pending further order by the FERC. On May 19, 2003, NRG PMI withdrew its notice of termination of the contract. On June 25, 2003, the FERC issued an order directing NRG PMI to continue to provide service to CL&P under the contract, pending further notice by the FERC. NRG PMI cannot estimate at this time the likelihood of an unfavorable outcome in this matter, or the overall exposure for congestion charges for the full term of the contract.

Connecticut Light & Power – Related Proceedings at the Federal Energy Regulatory Commission, the United States District Court for the Southern District of New York, and the United States Court of Appeals for the D.C. Circuit and the Second Circuit - In May, 2003, when NRG PMI took steps to terminate or reject in bankruptcy the subject standard offer services contract with CL&P (CL&P Contract), the Connecticut Attorney General and the Connecticut Department of Public Utility Control (DPUC) sought and obtained from the FERC its above-referenced May 16, 2003 order temporarily requiring NRG PMI to continue to comply with the terms of the CL&P Contract, pending further notice from the FERC. Thereafter, On June 2, 2003, the United States Bankruptcy Court for the Southern District of New York issued its Order specifically authorizing NRG PMI’s rejection of the CL&P Contract, and by Order dated June 12, 2003, the United States District Court for the Southern District of New York granted NRG PMI’s motion for a temporary restraining order staying all actions by CL&P, the Connecticut Attorney General and the DPUC to enforce or apply the above-referenced FERC order and affording NRG PMI leave to cease its performance under the CL&P Contract, effective retroactive to June 2, 2003. The FERC then issued an order on June 25, 2003, that again commanded NRG PMI’s continued performance regardless of any contrary ruling by the bankruptcy court and the District Court’s temporary restraining order. By order dated June 30, 2003, the District Court dismissed NRG PMI’s motion for preliminary injunction for lack of subject matter jurisdiction. On July 1, 2003, NRG PMI resumed performance under the CL&P Contract. On July 3, 2003, NRG PMI requested of the FERC a stay of the June 25 order which request was denied. On July 8, 2003, NRG PMI requested an emergency stay of the FERC’s June 25 order pending petition for review from the United States Court of Appeals for the District of Columbia Circuit. On July 16, 2003, the District of Columbia Circuit denied NRG PMI’s request for a stay of the June 25 order. On July 17, 2003, NRG PMI appealed to the Second Circuit respecting the District Court’s refusal to enjoin the FERC and maintain the restraining order. On July 18, 2003, NRG PMI requested emergency injunctive relief with respect to performance under the CL&P Contract and an expedited briefing schedule on the appeal. NRG awaits the Second Circuit’s decision on the above appeal as well as a permanent order by the FERC with respect to NRG PMI’s continued performance under the CL&P Contract. Should NRG PMI have to perform for the duration of the CL&P Contract, this could have an adverse financial consequence approaching $100 million.

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 8.25% Senior Unsecured Notes due 2010 issued by NRG

• Failure to make $14.4 million interest payment due on Sept. 16, 2002

• Failure to make $14.4 million interest payment due on March 17, 2003

$250 million 8.70% Remarketable or Redeemable Securities due 2005 issued by NRG Energy Pass-Through Trust 2000-1

• Failure to make $10.9 million interest payment due on Sept. 16, 2002

• Failure to make $10.9 million interest payment due on March 17, 2003

$240 million 8.0% Remarketable or Redeemable Securities due 2013 issued by NRG

• Failure to make $9.6 million interest payment due on Nov. 1, 2002

• Failure to make $9.6 million interest payment due on May 1, 2003

$350 million 7.75% Senior Unsecured Notes due 2011 issued by NRG

• Failure to make $13.6 million interest payment due on Oct. 1, 2002

• Failure to make $13.6 million interest payment due on April 1, 2003

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

• Failure to make $21.6 million interest payment due on Oct. 1, 2002

• Failure to make $21.6 million interest payment due on April 1, 2003

$300 million of 7.50% Senior Unsecured Notes due 2009 issued by NRG

• Failure to make $11.3 million interest payment due on Dec. 1, 2002
Failure to make $11.3 million interest payment due on June 1, 2003

$250 million of 7.50% Senior Unsecured Notes due 2007 issued by NRG

• Failure to make $9.4 million interest payment due on Dec. 15, 2002
Failure to make $9.4 million interest payment due on June 15, 2003

$340 million of 6.75% Senior Unsecured Notes due 2006 issued by NRG

• Failure to make $11.5 million interest payment due on Jan. 15, 2003

$125 million of 7.625% Senior Unsecured Notes due 2006 issued by NRG

• Failure to make $4.8 million interest payment due on Feb. 1, 2003

NRG Equity Units (NRZ) and related 6.50% Senior Unsecured Debentures due 2006 issued by NRG

• Failure to make $4.7 million interest payment due on Nov. 16, 2002

• Failure to make $4.7 million interest payment due on Feb. 17, 2003

$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 $6.5 million interest payment due on Sept. 30, 2002

• Failure to make $18.6 million interest payment due on Dec. 31, 2002

• Failure to make $17.8 million interest payment due on March 31, 2003
Failure to make $18.0 million interest payment due on June 30, 2003

• Missed minimum interest coverage ratio of 1.75x

• Violated minimum net tangible worth of $1.5 billion

• Notice of default issued on Feb. 27, 2003, rendering the debt immediately due and payable

$125 million Standby Letter of Credit Facility dated Nov. 30, 1999, among NRG, Australia and New Zealand Banking Group Limited, as Administrative Agent, and the 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
Availability reduced to the amount outstanding, which was $103 million as of June 30, 2003

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

• Failure to make $46.9 million in combined interest payments as of March 31, 2003

• Failure to fund equity obligations for construction

• Failure to post collateral requirements due under equity support agreement

• Acceleration of debt on Nov. 6, 2002, rendering the debt immediately due and payable

$325 million Series A floating rate Senior Secured Bonds due 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 and other amounts due on NRG Energy’s debt for borrowed money in excess of $50 million in the aggregate

• Notice of default issued on Oct. 22, 2002

• Acceleration of debt on May 13, 2003, rendering the debt immediately due and payable

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

• Failure to make $20.2 million interest and $12.8 million principal payment due on Sept. 16, 2002

• Failure to make $12.8 million principal payment due on March 17, 2003

• Failure to fund debt service reserve account

• Acceleration of debt on Nov. 21, 2002, rendering the debt immediately due and payable

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

• Failure to make $14.2 million interest payment due on Sept. 16, 2002

• Failure to fund debt service reserve account

• Acceleration of debt on Nov. 21, 2002, rendering the debt immediately due and payable

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

• Failure to make $53.5 million principal payment on Dec. 15, 2002

• Failure to fund debt service reserve account

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

• Failure to fund debt service reserve account

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

• Failure to fund debt service reserve account

$580 million Loan Agreement dated June 25, 2001, as amended, among MidAtlantic 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, among, LSP Kendall Energy LLC, Societe General, as Administrative Agent and the other parties thereto

• Liens placed against project assets

$181 million Loan Agreement dated Nov. 30, 2001, as amended, among McClain LLC and Westdeutsche Landesbank Girozentrale, as Administrative Agent

• Failure to fund the debt service reserve account

• Failure to comply with revenue allocation procedures under Article 3 of the Energy Management Services Agreement

In addition to the foregoing, there may be additional technical defaults with respect to these or other NRG debt instruments. Further, defaults on or acceleration of the foregoing debt instruments may result in cross-defaults on or cross-acceleration of these or other NRG debt instruments.

Item 4. Submission of Matters to a Vote of Security Holders

Xcel Energy’s Annual Meeting of Shareholders was held on June 11, 2003, for the purpose of voting on the matters listed below. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934, and there were no solicitations in opposition to management’s solicitations. All of management’s nominees for directors as listed in the proxy statement were elected. The voting results were as follows:

1. A proposal to elect four directors to Class II until the 2006 Annual Meeting of Shareholders:


Election of Director	Shares Voted For		Withheld Authority

Wayne H. Brunetti		304,218,950		28,855,689
Roger R. Hemminghaus		308,440,863		24,633,776
Douglas W. Leatherdale		310,331,061		22,743,578
A. Patricia Sampson		310,080,945		22,993,694

2. Proposal to approve resolution eliminating the classification of terms of the board of directors:


Shares Voted For	Shares Voted Against		Shares Abstained

117,153,946		105,814,511		8,373,887

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

The following Exhibits are filed with this report:

4.01 Supplemental Trust Indenture dated June 15, 2003 from Xcel Energy to Wells Fargo Bank Minnesota, N.A., Trustee.

10.01 Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc., as amended and restated effective Jan. 1, 2001

10.02 Separation Agreement dated Oct. 26, 2001, between Xcel Energy Inc. and Ben Fowke

31.01 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.01 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

99.01 Statement pursuant to Private Securities Litigation Reform Act.

99.02 Unaudited consolidated pro forma financial information — accounting for NRG on the equity method

(b) Reports on Form 8-K

The following reports on Form 8-K were filed either during the three months ended June 30, 2003, or between June 30, 2003, and the date of this report:

Aug. 1, 2003 (filed Aug. 1, 2003) – Items 12 and 7 Results of Operations and Financial Statements and Exhibits — Re: Preliminary Earnings Release of Xcel Energy.

June 20, 2003 (filed June 23, 2003) – Items 5 and 7 Other Events and Financial Statements and Exhibits — Re: Private Placement of Long-Term Debt by Xcel Energy.

June 13, 2003 (filed June 13, 2003) – Items 5 and 7 Other Events and Financial Statements and Exhibits — Re: Press Release regarding e prime.

June 9, 2003 (filed June 9, 2003) – Items 7 and 9 Financial Statements and Exhibits and Regulation FD Disclosure — Re: Presentation to Deutsche Bank Conference.

April 29, 2003 (filed April 29, 2003) – Items 7 and 9 Financial Statements and Exhibits and Results of Operations and Financial Condition — Re: Preliminary Earnings Release of Xcel Energy for the First Quarter of 2003.

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: Aug. 15, 2003

	•		$350 million would be paid at or shortly following the effective date of the NRG plan of reorganization. It is expected that this payment would be made in early 2004.

	•		$50 million also would be paid in early 2004, and all or any part of such payment could be made, at Xcel Energy’s election, in Xcel Energy common stock.

	•		Up to $352 million would be paid on April 30, 2004, unless at such time Xcel Energy had not received tax refunds equal to $352 million associated with the loss on its investment in NRG. To the extent Xcel Energy had not received such refunds, the April 30 payment would be due on May 30, 2004.

	•		The effective date of the NRG plan of reorganization for the NRG voluntary bankruptcy proceeding occurring on or prior to Dec. 15, 2003;

	•		The final plan of reorganization approved by the bankruptcy court and related documents containing terms satisfactory to Xcel Energy, NRG and various groups of the NRG creditors;

	•		The receipt of releases in favor of Xcel Energy from holders of at least 85 percent of the general unsecured claims held by NRG’s creditors; and

	•		The receipt by Xcel Energy of all necessary regulatory and other approvals.

	•		NRG’s disclosure statement filed with the SEC under PUHCA in July 2003;

	•		SEC acts on NRG’s disclosure statement in September 2003;

	•		Completion of the solicitation process of NRG’s reorganization in October 2003; and

	•		Confirmation hearing on NRG’s plan of reorganization in November 2003.

	•		annual base rate decreases of approximately $33 million for natural gas and $230,000 for electricity, including an annual reduction to electric depreciation expense of approximately $20 million, effective July 1, 2003;

	•		an interim adjustment clause (IAC) that recovers 100 percent of prudently incurred 2003 electric fuel and purchased energy expense above the expense recovered through electric base rates during 2003. This clause is projected to recover energy costs totaling approximately $216 million in 2003;

	•		a new electric commodity adjustment clause (ECA) for 2004-2006, with an $11.25-million cap on any cost sharing over or under an allowed ECA formula rate; and

	•		an authorized return on equity of 10.75 percent for electric operations and 11.0 percent for natural gas and thermal energy operations.

	•		NRG Bankruptcy or Insolvency — Bankruptcy plan of reorganization (Notes 4 and 6 describe the current status of certain financial contingencies related to NRG);

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

	•		Asset Valuation — Recoverability of investment in under-performing nonregulated projects (Seren, Argentina); and

	•		Guarantees — See Note 9 for discussion of exposures under various guarantees.

	•		instruments that represent, or are indexed to, an obligation to buy back the issuer’s shares, regardless whether the instrument is settled on a net-cash or gross physical basis;

	•		mandatorily redeemable equity instruments;

	•		written options that give the counterparty the right to require the issuer to buy back shares; and

	•		forward contracts that require the issuer to purchase shares.

•		general economic conditions, including their impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms;

•		business conditions in the energy industry;

•		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;

•		the financial condition of NRG;

•		actions by the bankruptcy court;

•		failure to realize expectations regarding the NRG settlement agreement;

•		currency translation and transaction adjustments;

•		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 Form 10-Q for the quarter ended June 30, 2003.

	•		PSCo expects to issue up to $575 million of debt for working capital and repayment of short-term borrowings incurred for the redemption of $194 million of Trust Originated Preferred Securities and $145 million of 8.75 percent first mortgage bonds. Both issues were redeemed on June 30, 2003. PSCo has entered into a bridge financing arrangement to provide short-term liquidity until it completes its long-term debt offering.

	•		NSP-Wisconsin expects to issue up to $150 million of debt to replace debt maturing in 2003 and for possible refinancing of existing long-term with lower coupon debt.

	•		SPS may issue up to $100 million of debt for refinancing of higher coupon securities.

	•		Failure to make $14.4 million interest payment due on Sept. 16, 2002

	•		Failure to make $14.4 million interest payment due on March 17, 2003

	•		Failure to make $10.9 million interest payment due on Sept. 16, 2002

	•		Failure to make $10.9 million interest payment due on March 17, 2003

	•		Failure to make $9.6 million interest payment due on Nov. 1, 2002

	•		Failure to make $9.6 million interest payment due on May 1, 2003

	•		Failure to make $13.6 million interest payment due on Oct. 1, 2002

	•		Failure to make $13.6 million interest payment due on April 1, 2003

	•		Failure to make $21.6 million interest payment due on Oct. 1, 2002

	•		Failure to make $21.6 million interest payment due on April 1, 2003

	•		Failure to make $4.7 million interest payment due on Nov. 16, 2002

	•		Failure to make $4.7 million interest payment due on Feb. 17, 2003

	•		Failure to make $6.5 million interest payment due on Sept. 30, 2002

	•		Failure to make $18.6 million interest payment due on Dec. 31, 2002

	•		Failure to make $17.8 million interest payment due on March 31, 2003 Failure to make $18.0 million interest payment due on June 30, 2003

	•		Missed minimum interest coverage ratio of 1.75x

	•		Violated minimum net tangible worth of $1.5 billion

	•		Notice of default issued on Feb. 27, 2003, rendering the debt immediately due and payable

	•		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 Availability reduced to the amount outstanding, which was $103 million as of June 30, 2003

	•		Failure to make $46.9 million in combined interest payments as of March 31, 2003

	•		Failure to fund equity obligations for construction

	•		Failure to post collateral requirements due under equity support agreement

	•		Acceleration of debt on Nov. 6, 2002, rendering the debt immediately due and payable

	•		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 and other amounts due on NRG Energy’s debt for borrowed money in excess of $50 million in the aggregate

	•		Notice of default issued on Oct. 22, 2002

	•		Acceleration of debt on May 13, 2003, rendering the debt immediately due and payable

	•		Failure to make $20.2 million interest and $12.8 million principal payment due on Sept. 16, 2002

	•		Failure to make $12.8 million principal payment due on March 17, 2003

	•		Failure to fund debt service reserve account

	•		Acceleration of debt on Nov. 21, 2002, rendering the debt immediately due and payable

	•		Failure to make $14.2 million interest payment due on Sept. 16, 2002

	•		Failure to fund debt service reserve account

	•		Acceleration of debt on Nov. 21, 2002, rendering the debt immediately due and payable

	•		Failure to make $53.5 million principal payment on Dec. 15, 2002

	•		Failure to fund debt service reserve account

	•		Failure to fund the debt service reserve account

	•		Failure to comply with revenue allocation procedures under Article 3 of the Energy Management Services Agreement

4.01		Supplemental Trust Indenture dated June 15, 2003 from Xcel Energy to Wells Fargo Bank Minnesota, N.A., Trustee.

10.01		Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc., as amended and restated effective Jan. 1, 2001

10.02		Separation Agreement dated Oct. 26, 2001, between Xcel Energy Inc. and Ben Fowke

31.01		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.01		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

99.01		Statement pursuant to Private Securities Litigation Reform Act.

99.02		Unaudited consolidated pro forma financial information — accounting for NRG on the equity method