Edgar Filing: XCEL ENERGY INC

e424b3

Filed Pursuant to Rule 424(b)(3)
File Number 333-103258

PROSPECTUS SUPPLEMENT
NO. 12

To Prospectus dated May 14, 2003 (SEC File No. 333-103258)

XCEL ENERGY INC.
800 Nicollet Mall, Suite 3000
Minnesota, Minneapolis 55402-2023
(612) 330-5500

$230,000,000
7½% Senior Convertible Notes
due 2007
and
Shares of Common Stock issuable upon conversion of the Notes

This Prospectus Supplement No. 12 includes the attached Quarterly Report on Form 10-Q of Xcel Energy Inc. for the quarter ended September 30, 2003 filed by us with the Securities and Exchange Commission. This Prospectus Supplement No. 12 supplements information contained in the Prospectus dated May 14, 2003, as amended, covering resale by selling security holders of our 7½% Senior Convertible Notes due 2007 and shares of our common stock issuable upon conversion of the notes. This Prospectus Supplement No. 12 is not complete without, and may not be delivered or utilized except in connection with, the Prospectus, including any amendments or supplements thereto.

Our common stock is traded on the New York Stock Exchange under the symbol “XEL”.

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS SUPPLEMENT. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

For more information please see the Prospectus and the Prospectus Supplements.

The date of this Prospectus Supplement No. 12 is November 21, 2003

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 Sept. 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 Oct. 31, 2003

Common Stock, $2.50 par value		398,824,602 shares

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION
	Item 1. Financial Statements
		CONSOLIDATED STATEMENTS OF OPERATIONS
		CONSOLIDATED STATEMENTS OF CASH FLOWS
		CONSOLIDATED BALANCE SHEETS
		CONSOLIDATED BALANCE SHEETS
		CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
		CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
	Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	Item 4. CONTROLS AND PROCEDURES
Part II — OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 3. Defaults Upon Senior Securities
	Item 6. Exhibits and Reports on Form 8-K

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 Sept. 30,						Nine Months Ended Sept. 30,

			2003			2002			2003			2002

						(As Restated)						(As Restated)
Operating revenues:
	Electric utility		$	1,760,039		$	1,556,942		$	4,507,913		$	4,117,497
	Natural gas utility			183,112			138,268			1,122,797			937,814
	Electric and natural gas trading margin			10,997			2,127			18,264			4,472
	Nonregulated and other			103,576			748,025			326,347			1,937,902
	Equity earnings from unconsolidated NRG affiliates			—			27,643			—			69,841

		Total operating revenues		2,057,724			2,473,005			5,975,321			7,067,526
Operating expenses:
	Electric fuel and purchased power – utility			816,554			618,442			2,050,148			1,650,961
	Cost of natural gas sold and transported – utility			103,144			58,115			757,988			559,347
	Cost of sales – nonregulated and other			73,707			411,420			221,079			1,002,379
	Other operating and maintenance expenses – utility			386,276			352,863			1,149,748			1,088,337
	Other operating and maintenance expenses – nonregulated			35,517			193,127			99,357			565,341
	Depreciation and amortization			193,793			264,084			597,734			772,401
	Taxes (other than income taxes)			84,746			87,538			248,087			255,143
	Special charges (see Note 2)			2,980			2,628,160			11,752			2,702,809

		Total operating expenses		1,696,717			4,613,749			5,135,893			8,596,718

Operating income (loss)				361,007			(2,140,744	)		839,428			(1,529,192	)
Equity in losses of NRG				—			—			(363,825	)		—
Minority interest in NRG losses				—			—			—			13,580
Interest and other income, net of nonoperating expenses (see Note 12)				21,590			9,790			30,690			43,789
Interest charges and financing costs:
	Interest charges – net of amounts capitalized (includes other financing costs of $8,561, $13,270, $25,054 and $29,935, respectively)			105,074			166,343			320,737			555,921
	Distributions on redeemable preferred securities of subsidiary trusts			2,621			9,586			21,773			28,758

		Total interest charges and financing costs		107,695			175,929			342,510			584,679
Income (loss) from continuing operations before income taxes				274,902			(2,306,883	)		163,783			(2,056,502	)
Income taxes (benefit) (see Note 6)				(12,593	)		(679,844	)		39,837			(609,009	)

Income (loss) from continuing operations				287,495			(1,627,039	)		123,946			(1,447,493	)
Income (loss) from discontinued operations, net of tax (see Note 3)				—			(577,001	)		20,999			(565,741	)

Net income (loss)				287,495			(2,204,040	)		144,945			(2,013,234	)
Dividend requirements on preferred stock				1,060			1,060			3,180			3,180

Earnings (loss) available to common shareholders			$	286,435		$	(2,205,100	)	$	141,765		$	(2,016,414	)

Weighted average common shares outstanding (in thousands):
	Basic			398,751			397,405			398,728			376,565
	Diluted			418,128			397,405			399,144			376,565
Earnings per share – basic:
	Income (loss) from continuing operations		$	0.72		$	(4.10	)	$	0.31		$	(3.85	)
	Discontinued operations			—			(1.45	)		0.05			(1.50	)

		Earnings (loss) per share – basic	$	0.72		$	(5.55	)	$	0.36		$	(5.35	)

Earnings per share – diluted:
	Income (loss) from continuing operations		$	0.69		$	(4.10	)	$	0.31		$	(3.85	)
	Discontinued operations			—			(1.45	)		0.05			(1.50	)

		Earnings (loss) per share – diluted	$	0.69		$	(5.55	)	$	0.36		$	(5.35	)

See Notes to Consolidated Financial Statements

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


				Nine Months Ended Sept. 30,

				2003			2002

							(As Restated)
Operating activities:
	Net income (loss)			$	144,945		$	(2,013,234	)
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			618,781			800,648
		Nuclear fuel amortization			32,982			37,208
		Deferred income taxes			(153	)		(849,327	)
		Amortization of investment tax credits			(9,375	)		(10,285	)
		Allowance for equity funds used during construction			(18,140	)		(5,125	)
		Undistributed equity in losses (earnings) of unconsolidated affiliates, including NRG			362,424			(14,544	)
		Gain on sale of Viking Gas (2003) and nonregulated property (2002)			(35,799	)		(6,785	)
		Non-cash special charges – continuing operations (primarily asset impairment write-downs)			—			2,686,559
		Non-cash asset impairment charges and disposal losses – discontinued operations			—			616,829
		Unrealized loss (gain) on derivative financial instruments			53,671			(46,514	)
		Change in accounts receivable			754			(32,686	)
		Change in inventories			19,678			32,981
		Change in other current assets			(139,748	)		146,473
		Change in accounts payable			(131,521	)		81,847
		Change in other current liabilities			92,902			150,831
		Change in other noncurrent assets			(38,141	)		(166,962	)
		Change in other noncurrent liabilities			49,863			91,019

			Net cash provided by operating activities		1,003,123			1,498,933
Investing activities:
	Utility capital/construction expenditures				(638,886	)		(696,092	)
	Nonregulated capital expenditures and asset acquisitions				(41,806	)		(1,443,999	)
	Allowance for equity funds used during construction				18,140			5,125
	Investments in external decommissioning fund				(42,669	)		(47,141	)
	Equity investments, loans and deposits – nonregulated projects				(14,544	)		(108,383	)
	Proceeds from sale of discontinued operations and nonregulated property				122,493			40,465
	Decrease in restricted cash				23,000			—
	Other investments – net				(893	)		(52,129	)

			Net cash used in investing activities		(575,165	)		(2,302,154	)
Financing activities:
	Short-term borrowings – net				(379,814	)		(172,047	)
	Proceeds from issuance of long-term debt				1,381,984			2,318,152
	Repayment of long-term debt, including reacquisition premiums				(1,007,965	)		(510,899	)
	Proceeds from issuance of common stock				833			570,242
	Dividends paid				(227,455	)		(420,560	)

			Net cash (used in) provided by financing activities		(232,417	)		1,784,888
Net increase in cash and cash equivalents – continuing operations					195,541			981,667
Net decrease in cash and cash equivalents – reclassification of NRG to equity method					(385,055	)		—
Effect of exchange rate changes on cash					(16,061	)		5,979
Cash and cash equivalents at beginning of period					901,273			261,305

Cash and cash equivalents at end of period				$	695,698		$	1,248,951

See Notes to Consolidated Financial Statements

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


				Sept. 30,			Dec. 31,
				2003			2002

ASSETS
Current assets:
	Cash and cash equivalents			$	695,698		$	901,273
	Restricted cash				—			305,581
	Accounts receivable – net of allowance for bad debts of $26,792 and $92,745, respectively				710,525			961,060
	Accrued unbilled revenues				316,943			390,984
	Materials and supplies inventories – at average cost				181,707			321,863
	Fuel inventory – at average cost				52,993			207,200
	Natural gas inventories – replacement cost in excess of LIFO:
		$87,701 and $20,502, respectively			156,609			147,306
	Recoverable purchased natural gas and electric energy costs				193,926			63,975
	Derivative instruments valuation – at market				21,226			62,206
	Current deferred income taxes (see Note 6)				563,653			—
	Prepayments and other				225,101			273,770
	Current assets held for sale				—			101,950

			Total current assets		3,118,381			3,737,168

Property, plant and equipment, at cost:
	Electric utility plant				17,126,762			16,516,790
	Nonregulated property and other				1,672,453			8,411,088
	Natural gas utility plant				2,474,398			2,603,545
	Construction work in progress: utility amounts of $910,127 and $856,008, respectively				943,892			1,513,807

			Total property, plant and equipment		22,217,505			29,045,230
Less accumulated depreciation					(9,537,934	)		(10,303,575	)
Nuclear fuel – net of accumulated amortization: $1,091,513 and $1,058,531, respectively					90,199			74,139

			Net property, plant and equipment		12,769,770			18,815,794

Other assets:
	Investments in unconsolidated affiliates				130,938			1,001,380
	Notes receivable, including amounts from affiliates of $0 and $206,308, respectively				2,880			987,714
	Nuclear decommissioning fund and other investments				765,125			732,166
	Regulatory assets				741,815			576,403
	Derivative instruments valuation – at market				705			93,225
	Prepaid pension asset				467,328			466,229
	Goodwill – net of accumulated amortization of $581 and $7,000, respectively				7,730			35,538
	Intangible assets – net of accumulated amortization of $3,196 and $18,900, respectively				58,213			68,210
	Other				201,482			364,243
	Noncurrent assets held for sale				—			379,772

			Total other assets		2,376,216			4,704,880

			Total assets	$	18,264,367		$	27,257,842

See Notes to Consolidated Financial Statements

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


			Sept. 30,		Dec. 31,
			2003		2002

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	240,982	$	7,756,261
	Short-term debt			148,989		1,541,963
	Accounts payable			684,360		1,404,135
	Taxes accrued			355,106		267,214
	Dividends payable			—		75,814
	Derivative instruments valuation – at market			47,563		38,767
	NRG losses in excess of investment			927,414		—
	Other			389,348		749,521
	Current liabilities held for sale			—		515,161

		Total current liabilities		2,793,762		12,348,836

Deferred credits and other liabilities:
	Deferred income taxes			1,660,279		1,285,312
	Deferred investment tax credits			159,922		169,696
	Regulatory liabilities			597,426		518,427
	Derivative instruments valuation – at market			26,768		102,779
	Benefit obligations and other			352,376		560,981
	Asset retirement obligations (see Note 1)			1,008,534		—
	Customer advances			201,488		161,283
	Minimum pension liability			128,053		106,897
	Noncurrent liabilities held for sale			—		154,317

		Total deferred credits and other liabilities		4,134,846		3,059,692

Minority interest in subsidiaries				5,433		34,762
Commitments and contingent liabilities (see Note 8)
Capitalization:
	Long-term debt			6,411,736		6,550,248
	Mandatorily redeemable preferred securities of subsidiary trusts			100,000		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 – 398,779,232; 2002 – 398,714,039			4,714,330		4,664,984

		Total liabilities and equity	$	18,264,367	$	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 Sept. 30, 2003 and 2002
Balance at June 30, 2002			396,874	$	992,186	$	4,019,732	$	2,459,374		$	(16,881	)	$	(82,125	)	$	7,372,286
Net loss									(2,204,040	)								(2,204,040	)
Currency translation adjustments															(31,515	)		(31,515	)
After-tax net unrealized losses related to derivatives (see Note 10)															(25,036	)		(25,036	)
Unrealized gain on marketable securities															(1	)		(1	)

Comprehensive income for the period																		(2,260,592	)
Dividends declared:
	Cumulative preferred stock of Xcel Energy								(1,060	)								(1,060	)
	Common stock								(74,813	)								(74,813	)
Issuances of common stock – net			1,774		4,435		15,274											19,709
Other									90						(8	)		82
Repayment of ESOP loans												201						201

Balance at Sept. 30, 2002			398,648	$	996,621	$	4,035,006	$	179,551		$	(16,680	)	$	(138,685	)	$	5,055,813

Balance at June 30, 2003			398,732	$	996,830	$	3,888,803	$	(244,552	)	$	—		$	(257,064	)	$	4,384,017
Net income									287,495									287,495
Currency translation adjustments															(6,062	)		(6,062	)
After-tax net unrealized gains related to derivatives (see Note 10)															48,057			48,057
Unrealized loss on marketable securities															208			208

Comprehensive income for the period																		329,698
Dividends declared:
	Cumulative preferred stock of Xcel Energy								—									—
	Common stock								—									—
Issuances of common stock – net			47		118		497											615

Balance at Sept. 30, 2003			398,779	$	996,948	$	3,889,300	$	42,943		$	—		$	(214,861	)	$	4,714,330

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

Nine months ended Sept. 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 loss										(2,013,234	)								(2,013,234	)
Currency translation adjustments																16,982			16,982
After-tax net unrealized losses related to derivatives (see Note 10)																(4,348	)		(4,348	)
Unrealized gain on marketable securities																(29	)		(29	)

Comprehensive income for the period																			(2,000,629	)
Dividends declared:
	Cumulative preferred stock of Xcel Energy									(3,180	)								(3,180	)
	Common stock									(362,601	)								(362,601	)
Issuances of common stock – net			27,082		67,706		510,195												577,901
Acquisition of NRG minority common shares			25,765		64,412		555,222									28,150			647,784
Other										163						14			177
Repayment of ESOP loans													1,884						1,884

Balance at Sept. 30, 2002			398,648	$	996,621	$	4,035,006		$	179,551		$	(16,680	)	$	(138,685	)	$	5,055,813

Balance at Dec. 31, 2002			398,714	$	996,785	$	4,038,151		$	(100,942	)	$	—		$	(269,010	)	$	4,664,984
Net income										144,945									144,945
Currency translation adjustments																91,299			91,299
After-tax net unrealized losses related to derivatives (see Note 10)																(12,532	)		(12,532	)
Minimum pension liability																(24,837	)		(24,837	)
Unrealized loss on marketable securities																219			219

Comprehensive income for the period																			199,094
Dividends declared:
	Cumulative preferred stock of Xcel Energy									(1,060	)								(1,060	)
	Common stock						(149,521	)											(149,521	)
Issuances of common stock – net			65		163		670												833

Balance at Sept. 30, 2003			398,779	$	996,948	$	3,889,300		$	42,943		$	—		$	(214,861	)	$	4,714,330

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) as of Sept. 30, 2003, and Dec. 31, 2002; the results of its operations and stockholders’ equity for the three and nine months ended Sept. 30, 2003 and 2002; and its cash flows for the nine months ended Sept. 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 consolidated financial statements, during the second quarter of 2003, Xcel Energy changed its accounting and reporting of its subsidiary NRG Energy, Inc. (NRG) to the equity method for all 2003 financial results. Prior financial information continues to reflect NRG as a consolidated entity. See Note 5 to the consolidated financial statements.

Results for the third quarter of 2002 reflect restatement of NRG asset impairments and certain financing transactions, as discussed in Note 16 to the consolidated financial statements. Xcel Energy also reclassified certain items in the 2002 statement of operations, statement of cash flows and balance sheet to conform to the 2003 presentation. These reclassifications had no effect on restated stockholders’ equity, net income or earnings per share as previously reported.

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.”

Utility Impact of Adopting SFAS No. 143 - Asset retirement obligations were recorded for the decommissioning of two Northern States Power Company (NSP-Minnesota), a Minnesota corporation, 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 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 approved by regulators		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 nine months ended Sept. 30, 2003.


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

Steam plant retirement		$	2,725	$	—	$	—	$	101	$	—	$	2,826
Nuclear plant decommissioning			859,643		—		—		42,380		103,685		1,005,708

	Total liability	$	862,368	$	—	$	—	$	42,481	$	103,685	$	1,008,534

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. This regulatory asset is expected 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.

In August 2003, prior estimates for the nuclear plant decommissioning obligations were revised to incorporate the assumptions made in NSP-Minnesota’s updated 2002 nuclear decommissioning filing with the Minnesota Public Utilities Commission (MPUC) in August 2003. The revised estimates resulted in an increase of $104 million to both the regulatory asset and the long-term liability, discussed previously. The revised estimates reflected changes in cost estimates due to changes in the escalation factor, changes in the estimated start date for decommissioning and changes in assumptions for storage of spent nuclear fuel. The changes in assumptions for the estimated start date for decommissioning and changes in the assumptions for storage of spent nuclear fuel are a result of recent Minnesota legislation that authorized additional spent nuclear fuel storage, as discussed in Note 14 to the consolidated financial statements.

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 Xcel Energy or 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 NSP-Minnesota assets legally restricted for purposes of settling the nuclear asset retirement obligations is $844 million as of Sept. 30, 2003, including external nuclear decommissioning investment funds and internally funded amounts.

The adoption of SFAS No. 143 in 2003 also affects 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. 71 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 Light, Fuel & Power Co			9

	Total Xcel Energy	$	809

Special Charges

Special charges included in Operating Expenses include the following:


		Three Months Ended				Nine Months Ended

(Thousands of Dollars)		Sept. 30, 2003		Sept. 30, 2002		Sept. 30, 2003		Sept. 30, 2002

NRG asset impairments and restructuring costs		$	—	$	2,500	$	—	$	2,556
NRG losses from equity investment disposals			—		117		—		122
Other investment disposal losses			—		11		—		11
Holding company costs related to NRG			3		—		12		—
Regulatory recovery adjustment			—		—		—		5
Restaffing			—		—		—		9

	Total special charges	$	3	$	2,628	$	12	$	2,703

Holding Company Costs (2003) – During the first nine months of 2003, the Xcel Energy holding company incurred approximately $12 million for charges related to NRG’s financial restructuring, including $3 million in the third quarter of 2003.

NRG Special Charges (2002) – In the second quarter of 2002, NRG expensed pretax charges of $36 million, or 6 cents per share, related to its NEO projects and $20 million, or 4 cents per share, for expected severance and related benefits. Additional severance accruals of $6 million, or 1 cent per share, were made in the third quarter of 2002. Through Sept. 30, 2002, severance costs had been recognized for all employees who had been terminated as of that date. Another $12 million, or 2 cents per share, of other NRG restructuring costs were recorded in the third quarter of 2002, including financial advisors, legal advisors and consultants. In addition, NRG also recorded a $16 million charge to income in the third quarter of 2002, for a decrease in the value of a remarketing option.

Due to financial difficulties (as discussed in Xcel Energy’s 2002 Annual Report on Form 10-K), NRG’s continuing operations incurred $2.6 billion of asset impairments and estimated disposal losses related to projects and equity investments, respectively, with lower expected cash flows or fair values. These charges, recorded in the third quarter of 2002, included write-downs of $2.2 billion for projects in development, $265 million for operating projects and $117 million for equity investments.

As discussed further in Note 5 to the consolidated 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 consolidated financial statements, but are not presented as a special charge in 2003.

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 nine months of 2003:


		Dec. 31, 2002		Adjustments						Sept. 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		—			(10	)		3

	Total accrued special charges	$	31	$	(18	)	$	(10	)	$	3

* 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 Sept. 30, 2003.

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

Other (2002) – During the third quarter of 2002, Xcel International disposed of its remaining interest in Yorkshire Power LLC in the United Kingdom, resulting in a pre-tax loss of $11.1 million and an after-tax loss of $8.3 million, or 2 cents per share.

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).

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			Nine Months Ended

(Thousands of Dollars)		Sept. 30, 2002			Sept. 30, 2002

Operating revenues		$	184,733		$	543,027
Operating and other expenses			(162,690	)		(499,864	)
Asset impairment charges			(599,732	)		(599,732	)

	Pretax loss from discontinued operations		(577,689	)		(556,569	)
Income taxes			(8,111	)		(7,925	)

	Loss from discontinued operations		(569,578	)		(548,644	)
Pretax loss from disposal			(7,423	)		(17,097	)

	Net loss from discontinued operations	$	(577,001	)	$	(565,741	)

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 consolidated 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.

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 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 outstanding 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 NRG 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. 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 and claims of NRG creditors who release Xcel Energy under the NRG plan of reorganization described below.


		•		$350 million (including $112 million payable to NRG’s bank lenders) 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 commencing on April 30, 2004, unless at such time Xcel Energy had not received tax refunds equal to at least $352 million associated with the loss on its investment in NRG. To the extent such refunds are less than the required payments, the difference between the required payments and those refunds would be due on May 30, 2004.

	•		$390 million of the up to $752 million of total 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 voluntary releases from at least 85 percent of the unsecured claims held by NRG creditors, including releases from 100 percent of NRG’s bank creditors. 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 payments becoming due commencing on April 30, 2004.

	•		Upon the consummation of NRG’s debt restructuring through a bankruptcy proceeding, Xcel Energy’s exposure on any guarantees, indemnities or other credit support obligations incurred by Xcel Energy for the benefit of NRG or any NRG subsidiary would be terminated or other arrangements would be made such that Xcel Energy has no further liability and any cash collateral posted by Xcel Energy would be returned. As of Oct. 31, 2003, no such cash collateral is posted.

	•		As part of the settlement, any intercompany claims of Xcel Energy against NRG or any subsidiary arising from the provision of 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 satisfied 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 subsidiaries would not be reconsolidated with Xcel Energy or any of its other affiliates for tax purposes at any

time after their March 2001 deconsolidation (except to the extent required by state or local tax law) or treated as a party to or otherwise entitled to the benefits of any existing tax-sharing agreement with Xcel Energy. However, NRG and certain subsidiaries would continue to be treated as they were under the December 2000 tax allocation agreement to the extent they remain part of a consolidated or combined state tax group that includes Xcel Energy. Under the settlement agreement, NRG would not be entitled to any tax benefits associated with the tax loss Xcel Energy expects to recognize as a result of the cancellation of its stock in NRG on the effective date of the NRG plan of reorganization.

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 (including releases from 100 percent of NRG’s bank 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 Sept. 30, 2003, an estimate of $811 million for the expected tax benefits related to the write-off, as discussed in Note 6 to the consolidated financial statements.

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 income tax purposes. Xcel Energy expects to file for a tax refund of approximately $325 million in the first quarter of 2004. This refund is based on a two-year carryback, as allowed under current tax law. The previous refund estimate of $355 million, as disclosed in June 2003, was based, in part, on an estimated 2002 tax liability that was recently determined to be lower than expected. The $30-million difference was refunded to Xcel Energy in October 2003.

As to the remaining $486 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, NRG and certain of its affiliates filed voluntary petitions in the United States Bankruptcy Court for the Southern District of New York 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, a holder 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. This agreement will become effective upon execution by holders of approximately an additional 10 percent in principal amount of NRG’s long-term notes and specified other noteholders and bondholders and by a majority of NRG bank lenders representing at least two-thirds in principal amount of NRG’s bank debt. At this time, it appears unlikely that the plan support agreement will receive the requisite signatures prior to the effective date of the reorganization. However it is expected that various settlement-related agreements incorporating the terms of the settlement, which will be exhibits or supplements to the plan of reorganization and would be subject to approval in connection with the confirmation of the plan of reorganization, would supercede the plan support agreement. If approved, these agreements would be expected to be executed when the plan of reorganization is confirmed.

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 proposed timeline for NRG to emerge from bankruptcy in 2003. Based on this schedule, the effective date of NRG’s plan of reorganization would be on or before Dec. 15, 2003. We cannot assure that this timeline will be met, that the NRG plan of reorganization will be approved or that NRG will complete the proposed restructuring.

	•		On Oct. 8, 2003, the Federal Energy Regulatory Commission (FERC) approved the transfer of NRG assets to NRG’s creditors;

	•		On Oct. 10, 2003, the SEC issued the necessary order under the Public Utility Holding Company Act of 1935 (PUHCA) regarding the bankruptcy filing of NRG, allowing NRG to proceed with the solicitation of approval from its creditors of its plan of reorganization;

	•		On Oct. 14, 2003, the solicitation for approval of NRG’s plan of reorganization commenced;

	•		On Nov. 12, 2003, votes on the plan of reorganization and objections to the plan of reorganization are due;

	•		On Nov. 21, and Nov. 24, 2003, confirmation hearings have been scheduled on NRG’s plan of reorganization; and

	•		Appeals to the NRG plan of reorganization must be filed within 10 days after the confirmation of NRG’s plan of reorganization.

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.

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 consolidated 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 up to $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 the Support Agreement in 2002 pursuant to which Xcel Energy agreed, under certain circumstances, to provide a $300 million contribution to NRG. Upon effectiveness of the NRG plan of reorganization, Xcel Energy’s obligation under the Support Agreement would be terminated.

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. Accounting for and Reporting of NRG

As discussed in Note 4 to the consolidated financial statements, on May 14, 2003, 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. In October 2003, NRG began soliciting its existing creditors for approval of a plan of reorganization based on a settlement agreement (also discussed in Note 4 to the consolidated financial statements), 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. 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 these limitations under the equity method, Xcel Energy has stopped recognizing equity in the losses of NRG subsequent to the quarter ended June 30, 2003. These limitations provide for loss recognition by Xcel Energy until its investment in NRG is written off to zero, with further loss recognition to continue if its financial commitments to NRG exist beyond amounts already invested. As of Sept. 30, 2003, Xcel Energy had recognized NRG losses to the point where they exceeded the investment made in NRG by $858 million, $106 million more than the amount of the $752 million financial commitment to NRG under the pro-forma settlement agreement discussed previously. See the reconciliation to the reported investment in the table below. 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-bankruptcy 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 required 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 Sept. 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:


(Millions of Dollars)			Sept. 30, 2003

	Stockholder’s deficit of NRG		$	(1,531	)
	NRG losses not recorded by Xcel Energy *			542
	Purchase accounting adjustments **			62

		Xcel Energy’s negative investment in NRG – liability		(927	)
Pro-forma adjustments to reflect divestiture of NRG and settlement terms:
	Reclassification of NRG’s other comprehensive income			24
	Reclassification of intercompany receivables to investment			45

		Pro-forma negative investment in NRG	$	(858	)
	Losses recognized in excess of financial commitments			106

		Level of estimated financial commitments to NRG	$	(752	)

*		These represent NRG losses incurred in the second and third quarters of 2003 that were in excess of 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 pro-forma negative investment in NRG of $858 million will be eliminated over time through the reversal of $106 million in excess losses upon NRG’s emergence from bankruptcy and through $752 million of expected cash settlement payments as described in Note 4 to the consolidated financial statements.

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


		3 months ended			9 months ended
(Millions of dollars)		Sept. 30, 2003			Sept. 30, 2003

Total NRG income (loss)		$	(285	)	$	(906	)
Losses (income) not recorded by Xcel Energy under the equity method			285			542

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

NRG Summarized Financial Information – The following is summarized financial information for NRG for the periods in 2003 during which NRG was not consolidated:

Results of Operations


	3 Months Ended			9 Months Ended
(Millions of dollars)	Sept. 30, 2003			Sept. 30, 2003

Operating revenues	$	671		$	1,772
Operating income (loss)		(242	)		(602	)
Net income (loss)		(285	)		(906	)

Financial Position


(Millions of dollars)		Sept. 30, 2003

Current assets		$	1,644
Other assets			8,531

	Total assets	$	10,175

Current liabilities		$	2,089
Other liabilities			9,617
Stockholder’s equity			(1,531	)

	Total liabilities and equity	$	10,175

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

During 2002, Xcel Energy recognized an initial estimate of the expected tax benefits of $706 million, based on a settlement agreement with the major NRG creditors, including an expected write-off of Xcel Energy’s investment in NRG for tax purposes. This benefit was based on the estimated tax basis of Xcel Energy’s cash and stock investments already made in NRG, and their expected deductibility for federal income tax purposes.

In late August 2003, Xcel Energy determined that the tax basis in NRG was greater than originally estimated and that additional state tax benefits were available related to its investment in NRG. Based on revised estimates, Xcel Energy recorded $105 million, or 25 cents per share, of additional tax benefits in the third quarter of 2003, which increased Xcel Energy’s cumulative income tax benefits related to its investment in NRG to $811 million. Based on the expected timing of NRG’s emergence from bankruptcy and the filing of 2003 tax returns and related carrybacks (as discussed in Note 4), approximately $564 million of these deferred tax benefits have been classified as a current asset at Sept. 30, 2003 to reflect refunds and estimated tax payment reductions expected in the 12 months after that date.

In addition, the expected settlement payments of $752 million may generate additional tax benefits and 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 at the time that such benefits are considered likely of realization 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 Investigations – As previously reported, the MPUC directed the Office of the Attorney General and the Minnesota Department of Commerce (state agencies) to investigate the accuracy of NSP-Minnesota’s electric reliability records, which are summarized and reported to the MPUC on a monthly basis with an annual true-up. On Aug. 4, 2003, the state agencies jointly filed with the MPUC a report issued by Fraudwise, an investigation firm 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 report indicated instances of inconsistency and misstatement in the record-keeping system, but noted that these instances of manipulation appear to have been limited to a small number of employees. NSP-Minnesota is continuing its internal review of these matters and has taken certain remedial and disciplinary actions to address the record-keeping deficiencies.

On Sept. 24, 2003, NSP-Minnesota and the state agencies announced that they had reached a settlement agreement that would be submitted to the MPUC for its approval. Among the provisions are:

	•		$1 million in refunds to Minnesota customers who have experienced the longest duration of outages, which have been accrued at Sept. 30, 2003;

	•		additional actions to improve system reliability in an effort to reduce outage frequency and duration. These actions will target the primary outage causes, including tree trimming and cable replacement. At least an additional $15 million, above amounts being currently recovered in rates, is to be spent in Minnesota on these outage prevention improvements by Jan. 1, 2005; and

	•		development of a revised service quality plan containing a standard for service outage documentation, new performance measures, new thresholds for current performance measures and a new structure for consequences that will result from failure to meet these performance measures.

NSP-Minnesota is currently negotiating the details of the revised service quality plan with the state agencies. The new service quality plan, or a report on the progress of the negotiations, is expected to be filed with the MPUC on Nov. 14, 2003.

In 2002, the South Dakota Public Utilities Commission (SDPUC) investigated Xcel Energy’s service quality. In particular, the investigation focused on NSP-Minnesota operations in the Sioux Falls area. NSP-Minnesota committed to a number of actions to improve reliability, which are being implemented, and to provide an updated 10-year capacity plan to the SDPUC by the end of 2003. NSP-Minnesota is working to complete the commitments made last December relating to service quality in the Sioux Falls area. NSP-Minnesota also 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 (TEMT) that would establish certain wholesale energy and transmission service rates based on locational marginal cost pricing (LMP) to be 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. After numerous parties, including several states, filed protests to the proposal, MISO filed on Oct. 17, 2003, to withdraw the TEMT without prejudice to refiling. The FERC issued an order approving the withdrawal and provided guidance on MISO’s proposals on Oct. 29, 2003. MISO is now starting the stakeholder consultation process to prepare and submit a revised TEMT in 2004. Management believes any 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.

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. Subsequent to the show cause order, PSCo provided information to the FERC staff showing PSCo did not engage in circular scheduling. On Aug. 29, 2003, the FERC trial staff filed a motion to dismiss PSCo from the show cause proceeding. Various California parties have opposed the motion to dismiss. They have also requested rehearing of the FERC’s show cause orders contending that the FERC should have named PSCo in the show cause orders as an entity that had engaged in a load shift transaction and a partnership that constituted gaming. PSCo has answered both the request for rehearing and the California parties’ opposition to the FERC staff’s motion to dismiss.

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. The CPUC issued its final decision in the rate case on Aug. 8, 2003. PSCo expects to file the rate design portion of the case on or before Dec. 8, 2003.

PSCo Fuel Adjustment Clause Proceedings - Certain wholesale electric sales customers of PSCo filed complaints with the FERC in 2002 alleging PSCo had 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. 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 answering 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. In August 2003, PSCo reached agreements in principle with all of the complainants under which such claims, as well as issues those customers had raised in response to PSCo’s wholesale general rate case filing (discussed below), were compromised and settled. Under the settlement agreements in principle, PSCo will make cash payments or billing credits to certain of the complaining customers totaling approximately $1.5 million. The settlements also provide for revisions to the base demand and energy rates filed in the PSCo wholesale electric rate case. PSCo and the other parties are negotiating the detailed settlement provisions, which are subject to FERC approval.

PSCo had a retail incentive cost adjustment (ICA) cost recovery mechanism in place for periods prior to 2003. The CPUC conducted a proceeding to review and approve the incurred and recoverable 2001 costs under the ICA. 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 and 2002 will be reduced by $1.6 million. Additional evaluation of the 2002 recoverable ICA costs will be conducted in a future proceeding. 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 and is expected to reduce 2004 rates by an estimated $4.6 million. The stipulation and settlement agreement was approved by the CPUC in September 2003.

At Sept. 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 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. 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. As discussed above, in August 2003, PSCo reached a settlement in principle in this case and the separate wholesale fuel clause cases.

PSCo Electric Department Earnings Test Proceedings – PSCo has filed with the CPUC its annual electric department earnings test reports for 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. On Oct. 31, 2003, the administrative law judge ruled the gain was appropriately included in the 2001 earnings, and it is reasonable to amortize the gain over four years. In the 2002 proceeding, the CPUC has opened a docket to consider whether PSCo’s cost of debt has been adversely affected by the financial difficulties at NRG and, if so, whether any adjustments to PSCo’s cost of capital should be made. The 2002 proceeding has been set for hearing in August 2004.

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. On Feb. 10, 2003, the administrative law judge issued a recommended decision rejecting the proposed disallowances and approving PSCo’s gas costs for the subject gas purchase year as prudently incurred. The CPUC upheld the finding that PSCo was prudent and reasonable in its handling of the Western Natural Gas default in January 2001.

PSCo Annual Gas Cost Adjustment Filing – PSCo recovers the cost of natural gas that it purchases for its customers’ use through a gas cost adjustment mechanism in its gas rates filed with the CPUC. On Sept. 16, 2003, PSCo requested an $88.8-million increase in prices for its customers through its annual gas cost adjustment filing to reflect higher current and forecasted costs of natural gas. The price increase was approved by the CPUC and went into effect on Oct. 1, 2003.

PSCo Capacity Cost Adjustment – In October 2003, PSCo filed with the CPUC an application to recover approximately $31.5 million of incremental capacity costs through a purchased capacity cost adjustment (PCCA) rider beginning March 1, 2004. The purpose of the PCCA is to recover purchased capacity payments to third party power suppliers that will not be recovered in PSCo’s current base electric rates or other recovery mechanism. In addition, PSCo has proposed to return to its retail customers 100 percent of any electric earnings in excess of its authorized rate of return on equity allowed in the last rate case, currently 10.75 percent. A decision by the CPUC is expected in 2004.

Home Builders Association of Metropolitan Denver (PSCo) – In February 2001, Home Builders Association of Metropolitan Denver (HBA) filed a complaint with the CPUC seeking a reparations award of $13.6 million for PSCo’s failure to update its gas extension policy construction allowances from 1996 to 2002 under its tariff. On Aug. 27, 2003, the CPUC issued a ruling with respect to this matter and on Sept. 24, 2003, adopted a written order in this proceeding. According to the CPUC decision, PSCo is to pay reparations to HBA members, including interest, based on a revised construction allowance for the period Feb. 24, 1999, through May 31, 2002. The level of reparations based on the revised construction allowance is not known at this time. However, management expects total reparations are likely to be less than $1.5 million. PSCo and HBA have both requested rehearing of the Aug. 27, 2003 CPUC order.

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 undercollected 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 underrecoveries 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 semiannual 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 became effective in September 2003. The Texas retail fuel factors will change each November and May based on the projected cost of natural gas. Revenues will continue to be reconciled to fuel costs in accordance with Texas law.

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. In August 2003, the parties to the case filed a stipulation resolving various issues. The stipulation provided approval of SPS’ modified request to surcharge $15.7 million for the months April 2003 and May 2003 over 12 months beginning with the November 2003 billing cycle. The stipulation was approved by the PUCT in October 2003.

In November 2003, SPS submitted a third fuel cost surcharge factor application in Texas to recover an additional $25 million of fuel cost underrecoveries accrued during June through September 2003. If approved, the proposed surcharge will go into effect after the first surcharge is completed and will continue for 12 months beginning in May 2004. This case is pending review and approval by the PUCT.

SPS New Mexico Fuel Reconciliation and Fuel Factor Applications – On May 27, 2003, a hearing examiner for the New Mexico Public Regulatory Commission (NMPRC) 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 undercollections. The decision denied the intervenors’ request that all margins from off-system sales be credited to ratepayers. On Aug. 19, 2003, the NMPRC approved the hearing examiner’s recommended decision. In accordance with NMPRC regulations, SPS must file its next New Mexico fuel factor continuation case no later than August 2005.

SPS New Mexico Billing Practice Investigation – On Sept. 25, 2003, the NMPRC entered an order opening an investigation into estimated billing practices used to send estimated bills to approximately 9,500 customers for between two and five months. As part of the Sept. 25, 2003, order, the NMPRC also implemented temporary billing measures for customers whose bills were estimated. The temporary billing measures: (i) require SPS to apply the lowest fuel and purchased power cost adjustment factor that was applicable during the period when meters were being estimated, (ii) allow customers six months to pay bills in full without additional charges or disconnection, (iii) prohibit disconnection of service until Nov. 1, 2003, for any customer that received an estimated bill, (iv) require a written explanation of the fuel calculation used under the order and (v) order a report of the amount of fuel and purchased power costs foregone as a result of the interim relief, which amount will not be allowed to be recovered from customers. The proceeding has been referred to a hearing examiner.

TRANSLink Transmission Co., LLC (TRANSLink) – In 2002, NSP-Minnesota filed for MPUC approval to transfer functional control of its transmission system to TRANSLink, a proposed independent transmission company. In June 2003, the MPUC held a hearing on the TRANSLink application. At the hearing, the MPUC deferred any decision and 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 and other parties. On Nov. 3, 2003, NSP-Minnesota submitted a status report to the MPUC indicating the participants are evaluating the TRANSLink proposal in light of recent events and would provide a further report within 30 days. Similar filings in North Dakota and Wisconsin are not contested, but have not been approved.

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 (SPP) 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 requested the cases be dismissed without prejudice while it evaluates possible RTO arrangements for the SPS system.

Xcel Energy is considering these developments, as well as the proceedings in process in other jurisdictions, to evaluate the future role

of TRANSLink in providing transmission operations services for the Xcel Energy system. As of Sept. 30, 2003, Xcel Energy’s subsidiaries had deferred approximately $5 million of TRANSLink-related costs based on anticipated recovery in future rates.

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. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on Xcel Energy’s financial position and results of operations.

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) – On Oct. 20, 2003, the U.S. District Court in Madison, Wisconsin entered a consent decree settling the EPA’s claims against NSP-Wisconsin related to the French Island generating plant, but denying any liability. The consent decree is now enforceable. On or before Nov. 19, 2003, NSP-Wisconsin will pay a civil penalty of $500,000.

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 believes it 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 PSCo and 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 (January 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 January 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 several 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 $28 million to the CFTC to settle alleged violations related to the reporting of fictitious transactions. The CFTC has also brought a civil complaint against an energy company alleging false reporting and attempted market manipulation. In the complaint, the CFTC requests damages as well as an order directing the energy company to disgorge benefits received from the alleged illegal acts. These and other energy companies are also subject to an 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 and Xcel Energy have suspended and/or 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 Dec. 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 court 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.

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

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 in St. Cloud, Minn. 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, Xcel Energy’s Seren subsidiary, 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. The court granted the plaintiffs’ request to amend the complaint to seek punitive damages against Seren and CCI. The plaintiffs brought a similar motion against NSP-Minnesota, which was subsequently denied by the court. On Nov. 11, 2003, court-ordered mediation was conducted. As a result of this mediation NSP-Minnesota reached a confidential settlement with a group of plaintiffs representing the most significant claims asserted against NSP-Minnesota. The settlements will be paid by NSP-Minnesota’s insurance carrier. A trial date has not been set for the remaining lawsuits.

Department of Labor Audit — In 2001, Xcel Energy received notice from the Department of Labor (DOL) Employee Benefit Security Administration that it intended to audit the Xcel Energy Pension Plan. After multiple on site meetings and interviews with Xcel Energy personnel, the DOL indicated on Sept. 18, 2003, that it is prepared to take the position that Xcel Energy, as plan sponsor and through its delegate the Pension Trust Administration Committee, breached its fiduciary duties under the Employee Retirement Income Security Act of 1974 (ERISA) with respect to certain investments made in limited partnerships and hedge funds in 1997 and 1998.

All discussions related to potential ERISA fiduciary violations have been preliminary and unofficial. The DOL has offered to conclude the audit at this time if Xcel Energy is willing to contribute to the plan the full amount of losses from each of these questioned investments, or approximately $13 million. Xcel Energy has responded with a letter to the DOL asserting that no fiduciary violations have occurred, and extending an offer to meet to discuss the matter further.

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 to the consolidated financial statements 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 underperforming nonregulated projects (Seren, Argentina); and

•		Guarantees — See Note 9 to the accompanying consolidated financial statements for discussion of exposures under various guarantees.

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

Short-Term Borrowings

At Sept. 30, 2003, Xcel Energy and its subsidiaries had approximately $149 million of short-term debt outstanding at a weighted average interest rate of 4 percent.

Long-Term Debt

On Oct. 6, 2003, SPS issued $100 million of 6 percent, Series C Senior Notes due 2033 in a private placement to qualified institutional buyers. On Oct. 15, 2003, the proceeds were used to redeem $100 million, 7.85 percent Trust Originated Preferred Securities of its trust subsidiary, Southwestern Public Service Capital I.

On Oct. 2, 2003, NSP-Wisconsin issued $150 million of 5.25 percent first mortgage bonds due Oct. 1, 2018 in a private placement to qualified institutional buyers. The proceeds were used to repay short-term debt incurred to pay at maturity $40 million of 5.75 percent first mortgage bonds due Oct. 1, 2003 and to redeem $110 million of 7.25 percent first mortgage bonds. On Oct. 15, 2003, NSP-Wisconsin redeemed the $110 million of 7.25 percent first mortgage bonds, due March 1, 2023.

On Oct. 1, 2003, NSP-Minnesota redeemed a total of $13.7 million of pollution control bonds consisting of $5.45 million related to the Minneapolis Community Development Agency, $3.4 million related to the city of Mankato and $4.85 million related to the city of Red Wing.

Preferred Stock

The third quarter dividend on the cumulative preferred stock of Xcel Energy was not declared on Sept. 30, 2003, pending final determination of retained earnings as of that date. 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. Xcel Energy had requested authorization from the SEC to pay its third quarter dividend out of capital and unearned surplus. However, no such authorization has yet been received. Consequently, cumulative preferred stock dividends of approximately $1.1 million were in arrears at Sept. 30, 2003. Amounts per share in arrears were as follows:


Series of Cumulative
Preferred Stock	Dividend per Share

$3.60	$	0.90
$4.08	$	1.02
$4.10	$	1.025
$4.11	$	1.0275
$4.16	$	1.04
$4.56	$	1.14

On Oct. 23, 2003, Xcel Energy declared the third quarter preferred stock dividends, based on the third quarter results, which indicated sufficient retained earnings were available to do so. The dividends were paid on Nov. 10, 2003, to preferred stock shareholders of record on Oct. 31, 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 Sept. 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		$	80	$	5
e prime			165		10
Other subsidiaries			84		3

	Total	$	329	$	18

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 to the consolidated financial statements 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 Sept. 30, 2003, was approximately $33 million, of which $6 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 amount of bonds outstanding.

Accounting Changes

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 of 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.

In November 2003, the FASB posted a staff position, which delayed the implementation of SFAS No. 150 indefinitely. On Sept. 30, 2003, SPS had a special purpose subsidiary trust with outstanding mandatorily redeemable preferred securities of $100 million consolidated in Xcel Energy’s Consolidated Balance Sheets. As stated previously, these securities were redeemed on Oct. 15, 2003. PSCo and NSP-Minnesota redeemed Trust Originated Preferred Securities on June 30, 2003, and July 31, 2003, respectively, and SFAS No. 150 will not affect such securities.

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, consolidation has been required for only subsidiaries in which an enterprise has a majority voting interest. Under FIN No. 46, an enterprise’s consolidated financial statements will include the consolidation of variable interest entities, which are entities that the enterprise has a controlling financial interest in. As a result, Xcel Energy expects that it will be required to consolidate all or a portion of its affordable housing investments made through Eloigne, which currently are accounted for under the equity method. Additionally, Xcel Energy is evaluating two other arrangements based on criteria in FIN No. 46, and it is likely that these arrangements will require consolidation.

As of Sept. 30, 2003, the assets of the affordable housing investments were approximately $146 million and long-term liabilities were approximately $78 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. Xcel Energy plans to adopt FIN No. 46 when required in the fourth quarter of 2003. The impact of consolidating these entities is not expected to have a material impact on net income.

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 Sept. 30,

(Millions of Dollars)	2003			2002

Accumulated other comprehensive income (loss) related to cash flow hedges at July 1	$	(38.5	)	$	82.3
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		47.5			53.4
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(12.6	)		(17.7	)
Regulatory deferral of costs to be recovered*		12.9			0.9
Discontinuance of hedge – NRG		—			(61.6	)

Accumulated other comprehensive income related to cash flow hedges – Sept. 30	$	9.3		$	57.3


	Nine months ended Sept. 30,

(Millions of Dollars)	2003			2002

Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	22.1		$	34.2
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		38.7			67.9
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(100.7	)		(11.9	)
Regulatory deferral of costs to be recovered*		17.2			1.3
Acquisition of NRG minority interest		—			27.4
Reversal of NRG forecasted transactions no longer probable		32.0			—
Discontinuance of hedge – NRG		—			(61.6	)

Accumulated other comprehensive income related to cash flow hedges – Sept. 30	$	9.3		$	57.3

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 identified 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 are designated as cash flow hedges for accounting purposes, and the changes in the fair value of these instruments are recorded as a component of Other Comprehensive Income. At Sept. 30, 2003, Xcel Energy had various commodity-related contracts deemed as cash flow hedges extending through 2009. Amounts deferred in Other Comprehensive Income are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the physical purchase or sale of electric energy, the use of natural gas to generate electric energy or gas purchased for resale. As of Sept. 30, 2003, Xcel Energy had net gains of $44.9 million accumulated in Other Comprehensive Income that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle. However, due to the volatility of commodities markets, the value in Other Comprehensive Income will likely change prior to its recognition in earnings.

Xcel Energy recorded losses of $0 million and $0.6 million related to ineffectiveness on commodity cash flow hedges during the three months ended Sept. 30, 2003 and 2002, respectively, and gains of $0 million and $0.4 million related to ineffectiveness on commodity cash flow hedges during the nine months ended Sept. 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 during the next 12 months net losses from Other Comprehensive Income of approximately $4.3 million.

Xcel Energy and its subsidiaries also enter into interest rate lock agreements that effectively fix the yield or price on a specified treasury security for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. Xcel Energy expects to reclassify into earnings during the next 12 months net gains from Other Comprehensive Income of approximately $1.4 million.

Hedge effectiveness is recorded based on the nature of the item being hedged. Hedging transactions for the sales of electric energy are recorded as a component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs, hedging transactions for gas purchased for resale are recorded as a component of gas costs and hedging transactions for interest rate swaps and interest rate lock agreements are recorded as a component of interest expense. Certain Xcel Energy utility subsidiaries are allowed to recover in electric or gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.

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) 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 Sept. 30, 2003, was $(5.6) million.

Hedges of Foreign Currency Exposure of a Net Investment in Foreign Operations

During 2002, to preserve the U.S. dollar value of projected foreign currency cash flows, Xcel Energy, through NRG, hedged those cash flows if appropriate foreign hedging instruments were available.

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

In addition, Xcel Energy recorded losses of $0 and $2.3 million related to the discontinuance of hedge accounting for the three and nine months ended Sept. 30, 2003 and three and nine months ended Sept. 30, 2002, respectively.

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. The results of these transactions are recorded within Operating Revenues on the Consolidated Statements of Operations.

Normal Purchases or Normal Sales Contracts

Xcel Energy and its utility subsidiaries enter into 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 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.

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 have been applied to contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003.

SFAS No. 133 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 during the fourth quarter of 2003 for Xcel Energy. 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 as a result of its ability to recover prudently-incurred purchased capacity costs from customers.

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
		Electric		Natural Gas						All			Reconciling			Consolidated
		Utility		Utility			NRG			Other			Eliminations			Total
(Thousands of Dollars)
Three months ended Sept. 30, 2003
Operating revenues from external customers		$	1,770,875	$	183,112		$	—		$	103,737		$	—		$	2,057,724
Intersegment revenues			269		6,359			—			16,620			(23,248	)		—
Equity earnings from unconsolidated NRG affiliates			—		—			—			—			—			—

	Total revenues	$	1,771,144	$	189,471		$	—		$	120,357		$	(23,248	)	$	2,057,724

Segment net income (loss)		$	201,753	$	(7,262	)	$	—		$	105,003		$	(11,999	)	$	287,495

Three months ended Sept. 30, 2002
Operating revenues from external customers		$	1,553,810	$	138,961		$	665,896		$	87,232		$	—		$	2,445,899
Intersegment revenues			281		(93	)		—			(12,383	)		11,658			(537	)
Equity earnings from unconsolidated NRG affiliates			—		—			27,643			—			—			27,643

	Total revenues	$	1,554,091	$	138,868		$	693,539		$	74,849		$	11,658		$	2,473,005

Segment net income (loss)		$	200,538	$	(10,732	)	$	(3,055,396	)	$	674,915		$	(13,365	)	$	(2,204,040	)


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

Nine months ended Sept. 30, 2003
Operating revenues from external customers		$	4,523,363	$	1,122,797	$	—		$	329,161	$	—		$	5,975,321
Intersegment revenues			830		9,907		—			60,551		(71,288	)		—
Equity earnings from unconsolidated NRG affiliates			—		—		—			—		—			—

	Total revenues	$	4,524,193	$	1,132,704	$	—		$	389,712	$	(71,288	)	$	5,975,321

Segment net income (loss)		$	357,378	$	53,051	$	(363,825	)	$	135,233	$	(36,892	)	$	144,945

Nine months ended Sept. 30, 2002
Operating revenues from external customers		$	4,114,715	$	937,751	$	1,688,250		$	256,249	$	—		$	6,996,965
Intersegment revenues			782		663		—			67,903		(68,628	)		720
Equity earnings from unconsolidated NRG affiliates			—		—		69,841			—		—			69,841

	Total revenues	$	4,115,497	$	938,414	$	1,758,091		$	324,152	$	(68,628	)	$	7,067,526

Segment net income (loss)		$	404,157	$	48,063	$	(3,123,211	)	$	684,753	$	(26,996	)	$	(2,013,234	)

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, net of Nonoperating Expenses

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


		3 months ended						9 months ended
		Sept. 30,						Sept. 30,

		2003			2002*			2003			2002*
(Thousands of Dollars)
Interest income		$	1,732		$	11,834		$	13,543		$	31,332
Equity income (loss) in unconsolidated affiliates (other than NRG)			3,179			326			(963	)		3,298
Other nonoperating income			7,718			508			20,968			22,050
Gain on sale of nonregulated assets			15,055			—			15,055			—
Minority interest expense (other than NRG)			2			(1,560	)		(827	)		(3,222	)
Other nonoperating expenses			(6,096	)		(1,318	)		(17,086	)		(9,669	)

	Total interest and other income, net of nonoperating expenses	$	21,590		$	9,790		$	30,690		$	43,789

* Includes NRG activity.

13. Common Stock and Incentive Stock Awards

Common Stock and Equivalents – Xcel Energy has common stock equivalents consisting of convertible senior notes and options. Due to the losses experienced in 2002, these equivalents were antidilutive and were not incorporated in the common stock and equivalents calculation in 2002. The convertible senior notes were also antidilutive for the nine months ended Sept. 30, 2003.

The dilutive impacts of common stock equivalents affected earnings per share as follows for the three- and nine-month periods ending Sept. 30, 2003:


	Three months ended Sept. 30, 2003							Nine months ended Sept. 30, 2003

(Shares and dollars in thousands,						Per-share							Per-share
except per share amounts)	Income			Shares		Amount		Income			Shares		Amount

Income from continuing operations	$	287,495						$	123,946
Less: Dividend requirements on preferred stock		(1,060	)						(3,180	)

Basic earnings per share:
Income from continuing operations		286,435			398,751	$	0.72		120,766			398,728	$	0.31

Effect of dilutive securities:
7.5% convertible notes		2,803			18,654				—			—
Options		—			723				—			416

Diluted earnings per share:
Income from continuing operations and assumed conversions	$	289,238			418,128	$	0.69	$	120,766			399,144	$	0.31

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, upon 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. Xcel Energy accrued approximately $9 million in the second quarter of 2003 and $6 million in the third quarter of 2003 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, if the quarter-end stock price and dividend payouts continue.

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 No. 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 its licenses with the 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 the requirement of 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 payments 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 $8.5 million in 2002 to $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 second quarter of 2003. 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.

16. NRG 2002 Restatement

Subsequent to the issuance of Xcel Energy’s financial statements for the quarter ended Sept. 30, 2002 but prior to the completion of Xcel Energy’s 2002 financial statements, NRG’s management determined that NRG had misapplied the provisions of SFAS No. 144 related to asset grouping in connection with the review for impairment of its long-lived assets during the quarter ended Sept. 30, 2002. SFAS No. 144 requires that for purposes of testing recoverability, assets be grouped at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets. NRG recalculated the asset impairment tests in accordance with SFAS No. 144 using the appropriate asset grouping for independent cash flows for each generation facility. As a result, NRG concluded that asset impairments should have been recorded for two projects known as Bayou Cove Peaking Power LLC and Somerset Power LLC. Since NRG concluded that the “triggering events” that led to the impairment charge were experienced in the third quarter of 2002, the asset impairments related to these projects should have been recorded as of Sept. 30, 2002. NRG calculated the asset impairment charges for Bayou Cove Peaking Power LLC and Somerset Power LLC to be $126.5 million and $49.3 million, respectively.

Additionally, NRG identified two items that had been inappropriately recorded as of Sept. 30, 2002. These items were the inappropriate treatment of interest rate swap transactions as cash flow hedges and the decrease in the value of a bond remarketing option from the original price paid by NRG. The error correction for the interest rate swaps resulted in the recording of additional income of $61.6 million as of Sept. 30, 2002. The recognition of the decrease in the value of the remarketing option resulted in a charge to income of $15.9 million as of Sept. 30, 2002.

A summary of the significant effects of the restatement on Xcel Energy’s consolidated statements of operations for the three and nine months ended Sept. 30, 2002, is as follows:


	As Previously Reported*						As Restated

	Three Months Ended			Nine Months Ended			Three Months Ended			Nine Months Ended
(Thousands of dollars, except per share amounts)	Sept. 30, 2002						Sept. 30, 2002

Consolidated statements of operations:
Special charges	$	2,436,467		$	2,511,116		$	2,628,160		$	2,702,809
Operating income (loss)		(1,949,051	)		(1,337,499	)		(2,140,744	)		(1,529,192	)
Interest charges		227,956			494,308			166,343			555,921
Income (loss) from continuing operations		(1,496,959	)		(1,317,413	)		(1,627,039	)		(1,447,493	)
Net income (loss)		(2,073,960	)		(1,883,154	)		(2,204,040	)		(2,013,234	)
Earnings (loss) available for common shareholders		(2,075,020	)		(1,886,334	)		(2,205,100	)		(2,016,414	)
Earnings (loss) per share from continuing operations: basic and diluted	$	(3.77	)	$	(3.51	)	$	(4.10	)	$	(3.85	)
Net earnings per share: basic and diluted	$	(5.22	)	$	(5.01	)	$	(5.55	)	$	(5.35	)

* Amounts previously reported include reclassifications of NRG operations, which became discontinued after Sept. 30, 2002 as discussed in Note 3 to the consolidated financial statements.

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

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

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “estimate,” “expect,” “objective,” “outlook,” “projected,” “possible,” “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:

•		general economic conditions, including the availability of credit, actions of rating agencies and their impact on access to capital;

•		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 relating to the NRG bankruptcy filing;

•		failure to realize expectations regarding the NRG settlement agreement;

•		failure of NRG to emerge from bankruptcy in 2003;

•		risks related to investigations and enforcement actions by state and federal regulators, including the CFTC, the SEC and the FERC; 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 Sept. 30, 2003.

RESULTS OF OPERATIONS

Xcel Energy owns or has an interest in a number of nonregulated businesses, the largest of which is 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) basis 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, the impact of tax benefits related to the investment in NRG and the results of NRG. The results of NRG under the equity method of accounting are excluded from 2003 Xcel Energy results, as required by GAAP. See Note 5 to the consolidated financial statements. Viking Gas was sold in January 2003, and we expect the outcome of NRG’s financial restructuring will be the divestiture of NRG in 2003. The pro-forma results are provided to reflect the ongoing operations of Xcel Energy on a comparative basis for 2003 and 2002.


			Three months ended						Nine months ended
			Sept. 30,						Sept. 30,

			2003			2002			2003			2002

GAAP Earnings (Loss) by Segment:
Regulated electric utility segment earnings			$	0.48		$	0.50		$	0.90		$	1.07
Regulated natural gas utility segment earnings – continuing operations				(0.02	)		(0.03	)		0.13			0.13
Other utility results*				(0.01	)		0.02			—			0.03

		Total utility segment earnings – continuing operations		0.45			0.49			1.03			1.23
Utility earnings – discontinued operations (gain from Viking Gas sale)*				—			—			0.05			—

		Total earnings from utility segments		0.45			0.49			1.08			1.23
NRG earnings (loss) – continuing operations				—			(6.24	)		(0.91	)		(6.75	)
NRG earnings (loss) – discontinued operations				—			(1.45	)		—			(1.50	)

		Total loss from NRG segment		—			(7.69	)		(0.91	)		(8.25	)
Other nonregulated results/holding company costs*				(0.01	)		(0.05	)		(0.07	)		(0.13	)
Tax benefit from investment in NRG (at holding company)*				0.25			1.70			0.26			1.80

	Total GAAP earnings (loss) per share – diluted		$	0.69		$	(5.55	)	$	0.36		$	(5.35	)

Reconciliation of Pro-Forma Results to GAAP Earnings (Loss):
Total utility segment earnings – continuing operations:			$	0.45		$	0.49		$	1.03		$	1.23
Other nonregulated results/holding company costs				(0.01	)		(0.05	)		(0.07	)		(0.13	)

		Pro-forma continuing operations, excluding NRG		0.44			0.44			0.96			1.10
Total NRG segment loss				—			(7.69	)		(0.91	)		(8.25	)
Tax benefit from investment in NRG (at holding company)*				0.25			1.70			0.26			1.80
Utility earnings – discontinued operations (gain on Viking Gas)*				—			—			0.05			—

		Total GAAP earnings (loss) per share — diluted	$	0.69		$	(5.55	)	$	0.36		$	(5.35	)

* 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 first and second quarter of 2002 reduced the utility segment earnings contribution by 6 cents per share, and the total loss by 2 cents per share, for the nine months ended Sept. 30, 2003.

Utility Segment Results

For the third quarter of 2003, net income from utility operations decreased largely due to higher purchased capacity costs and higher incentive and other employee benefit costs. Partially offsetting these decreases were increases in short-term wholesale and trading margins and retail electric sales growth. For the nine months ended Sept. 30, 2003, net income from continuing utility operations decreased largely due to higher financing and operating costs and lower nonregulated revenues, partially offset by higher electric margins. See below for additional discussion of specific margin and cost items affecting utility operating results.

Utility earnings per share were also reduced by 6 cents per share for the nine months ended Sept. 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

Three months ended Sept. 30	$	0.03	$	0.03	$	0.00
Nine months ended Sept. 30	$	0.02	$	0.06	$	(0.04	)

Other utility 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 consolidated financial statements.

NRG Segment Results

As discussed in Note 5 to the consolidated 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:


	Three months ended			Nine months ended
(Millions of Dollars)	Sept. 30, 2003			Sept. 30, 2003

Total NRG income (loss)*	$	(285	)	$	(906	)
Losses (income) not recorded by Xcel Energy under the equity method**		285			542

Equity in losses of NRG included in Xcel Energy results	$	—		$	(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 to the consolidated financial statements.

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 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 $106 million will be reversed and recognized as a non-cash gain upon NRG’s emergence from bankruptcy. During the third quarter of 2003, NRG recorded a $396 million charge in connection with the resolution of an arbitration claim with First Energy. See Note 5 to the consolidated 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.

As of Sept. 30, 2003, NRG’s 2003 operating results (excluding the unusual items discussed above) were affected by higher market prices due to higher natural gas prices and an increase in capacity revenues due to additional projects becoming operational in the later part of 2002. In addition, the sale of an NRG investment in 2002 resulted in a favorable impact in 2003, as the investment generated substantial equity losses in the prior years. The increase was offset by losses incurred on contracts in Connecticut due to increased market prices, increased operating expenses, contract terminations and liquidated damages triggered by NRG’s financial condition and additional restructuring charges.

Beginning in the third quarter of 2002, the likely tax filing status of NRG for 2002 and future years changed from being included as part of Xcel Energy’s consolidated federal income tax group to filing on a stand-alone basis. On a stand-alone basis, NRG 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 contributions of Xcel Energy’s nonregulated businesses other than NRG, and holding company results other than tax benefits from the investment in NRG:


		Three months ended						Nine months ended
		Sept. 30,						Sept. 30,

		2003			2002			2003			2002

Seren Innovations, Inc.		$	(0.01	)	$	(0.01	)	$	(0.03	)	$	(0.04	)
Planergy International			0.00			0.00			(0.01	)		(0.01	)
Eloigne Company			0.00			0.01			0.01			0.02
Xcel International			0.01			(0.02	)		0.02			(0.02	)
Financing costs and preferred dividends – holding company			(0.03	)		(0.03	)		(0.09	)		(0.08	)
Other			0.02			0.00			0.03			0.00

	Total other nonregulated and holding company (excluding NRG impacts)	$	(0.01	)	$	(0.05	)	$	(0.07	)	$	(0.13	)

Seren – Seren operates a combination cable television, telephone and high-speed Internet access system in St. Cloud, Minn., and Contra Costa County, California. At Sept. 30, 2003, Xcel Energy’s investment in Seren was approximately $266 million.

Xcel International – Xcel International owns and operates several energy projects in Argentina. Earnings in the third quarter and nine months ended increased in 2003 compared with 2002 due mainly to losses incurred in 2002 related to the sale of the remaining interests in Yorkshire Power in the United Kingdom. Also, earnings for the nine months ended Sept. 30, 2003, include a gain from a debt restructuring for one project, which increased earnings by approximately 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 and long-term debt in June 2003.

Other – In the third quarter of 2003, Utility Engineering sold water rights, resulting in a pretax gain (reported as nonoperating income) of $15 million. The gain increased net income by $10 million, or 2 cents per share, for the quarter. Results for the nine months ended also increased in 2003 mainly due to income tax adjustments related to changing state tax effects resulting from NRG tax deconsolidation and losses, partially offset by lower income from Utility Engineering and NRG restructuring costs, as discussed in Note 2 to the consolidated financial statements.

Tax Benefit from Investment in NRG – The table above excludes holding company tax impacts related to NRG. In the third quarter of 2003, Xcel Energy recorded $105 million, or 25 cents per share, of tax benefit related to its investment in NRG, as discussed in Note 6 to the consolidated financial statements.

Income Statement Analysis — Third Quarter 2003 vs. Third 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 between customers and shareholders relative to a target cost per delivered kilowatt-hour under the retail incentive cost adjustment (ICA) ratemaking mechanism. For 2003, PSCo 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, if applicable, 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
(Millions of	Electric			Term			Commodity			Commodity			Intercompany			Consolidated
Dollars)	Utility			Wholesale			Trading			Trading			Eliminations			Total

Three months ended Sept. 30, 2003
Electric utility revenue	$	1,717		$	43		$	—		$	—		$	—		$	1,760
Electric fuel and purchased power		(790	)		(27	)		—			—			—			(817	)
Electric and natural gas trading revenue		—			—			124			43			(5	)		162
Electric and natural gas trading costs		—			—			(113	)		(43	)		5			(151	)

Gross margin before operating expenses	$	927		$	16		$	11		$	—		$	—		$	954

Margin as a percentage of revenue		54.0	%		37.2	%		8.9	%		—	%		—	%		49.6	%
Three months ended Sept. 30, 2002
Electric utility revenue	$	1,507		$	50		$	—		$	—		$	—		$	1,557
Electric fuel and purchased power		(578	)		(40	)		—			—			—			(618	)
Electric and natural gas trading revenue		—			—			540			491			(20	)		1,011
Electric and natural gas trading costs		—			—			(543	)		(486	)		20			(1,009	)

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

Margin as a percentage of revenue		61.6	%		20.0	%		(0.6	)%		1.0	%		—	%		36.6	%

Base electric utility margins, primarily related to retail customers, decreased approximately $2 million for the third quarter of 2003, compared with the third quarter of 2002. The lower base electric margin reflects 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 accrued recovery of certain resource costs.

Short-term wholesale and electric commodity trading sales margins increased approximately $20 million for the third quarter of 2003. The increase reflects more favorable market conditions in the northern regions and reduced transmission costs.

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 Sept. 30,

(Millions of Dollars)	2003			2002

Natural gas utility revenue	$	183		$	138
Cost of natural gas sold and transported		(103	)		(58	)

Natural gas utility margin	$	80		$	80

Natural gas revenue increased by approximately $45 million, or 32.6 percent, 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 remained unchanged in the third quarter of 2003 compared with the same period in 2002, as higher gas costs offset the higher revenue from cost recovery.

Nonregulated Margins (Other than NRG)

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


		Three Months Ended Sept. 30,

(Millions of Dollars)		2003			2002

Nonregulated and other revenue		$	104		$	83
Nonregulated cost of goods sold			(74	)		(51	)

	Nonregulated margin	$	30		$	32

Nonregulated revenues for the third quarter increased in 2003 compared to 2002 due mainly to increasing customer levels in Seren’s communication business and higher contract revenues in Xcel International’s Argentina operations. The nonregulated margin decreased slightly due to higher cost of goods sold at Utility Engineering.

Non-Fuel Operating Expense and Other Costs

Utility Other Operation and Maintenance Expenses for the third quarter of 2003 increased by approximately $33 million, or 9.5 percent, compared with the third quarter of 2002. The increase is due primarily to higher employee benefit costs related to restricted stock unit grants, higher incentive costs, higher medical and health care costs and lower pension credits, and a scheduled refueling outage at the Prairie Island nuclear plant.

Excluding NRG amounts in 2002, interest expense decreased by approximately $4 million, or 3.5 percent, for the third quarter of 2003, compared with the third quarter of 2002. This decrease was primarily due to the refinancing of higher coupon debt at lower interest rates.

Excluding NRG amounts in 2002 and tax benefits related to the investment in NRG, 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 and excluding worthless stock deduction benefits was 33.6 percent in the third quarter of 2003 and 35 percent in the same quarter of 2002. See Note 6 to the consolidated financial statements for a discussion of tax benefits related to the investment in NRG.

Income Statement Analysis — First Nine Months of 2003 vs. First Nine 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
(Millions of	Base Electric			Term			Commodity			Commodity			Intercompany			Consolidated
Dollars)	Utility			Wholesale			Trading			Trading			Eliminations			Total

Nine months ended Sept. 30, 2003
Electric utility revenue	$	4,364		$	144		$	—		$	—		$	—		$	4,508
Electric fuel and purchased power		(1,951	)		(99	)		—			—			—			(2,050	)
Electric and natural gas trading revenue		—			—			256			507			(26	)		737
Electric and natural gas trading costs		—			—			(241	)		(504	)		26			(719	)

Gross margin before operating expenses	$	2,413		$	45		$	15		$	3		$	—		$	2,476

Margin as a percentage of revenue		55.3	%		31.3	%		5.9	%		0.6	%		—	%		47.2	%
Nine months ended Sept. 30, 2002
Electric utility revenue	$	3,985		$	132		$	—		$	—		$	—		$	4,117
Electric fuel and purchased power		(1,544	)		(107	)		—			—			—			(1,651	)
Electric and natural gas trading revenue		—			—			1,351			1,511			(57	)		2,805
Electric and natural gas trading costs		—			—			(1,353	)		(1,505	)		57			(2,801	)

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

Margin as a percentage of revenue		61.3	%		18.9	%		(0.1	)%		0.4	%		—	%		35.7	%

Base electric utility margins decreased approximately $28 million for the nine-month period of 2003 compared with the nine-month period of 2002. The lower base electric margin reflects cooler June temperatures, 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 accrued recovery of Minnesota renewable development fund costs.

Short-term wholesale and electric and commodity trading sales margins increased approximately $37 million for the first nine months of 2003 compared with the same period in 2002. The increase reflects more favorable market conditions in the northern regions and reduced transmission costs.

Natural Gas Utility Margins


	Nine Months Ended Sept. 30,

(Millions of Dollars)	2003			2002

Natural gas utility revenue	$	1,123		$	938
Cost of natural gas sold and transported		(758	)		(559	)

Natural gas utility margin	$	365		$	379

Natural gas revenue increased by approximately $185 million, or 19.7 percent, in the first nine 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.


		Nine Months Ended Sept. 30,

(Millions of Dollars)		2003			2002

Nonregulated and other revenue		$	326		$	250
Nonregulated cost of goods sold			(221	)		(163	)

	Nonregulated margin	$	105		$	87

Nonregulated revenues and margins for the third quarter increased in 2003 compared with 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 partially offset by higher cost of goods sold.

Non-Fuel Operating Expense and Other Costs

Utility operating and maintenance expenses for the nine months ended Sept. 30, 2003, increased approximately $61 million, or 5.6 percent, compared with the same period in 2002. The increase is due primarily to higher employee benefit costs related to lower pension credits, higher medical and health care costs, higher incentive costs and restricted stock unit grants, as well as higher outage costs, partly offset by lower information technology costs.

Excluding NRG amounts in 2002, depreciation and amortization increased by approximately $13 million, or 2.3 percent, for the first nine months of 2003, compared with 2002, primarily due to $14 million of Minnesota renewable development fund costs, which are largely recovered through NSP-Minnesota’s fuel clause mechanism, and increased software amortization, partially offset by lower depreciation rates at PSCo in 2003.

Excluding NRG amounts in 2002, interest expense increased by approximately $60 million for the first nine 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 and tax benefits related to the investment in NRG, 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 and excluding worthless stock deduction benefits was 27.5 percent in the first nine months of 2003 and 34.4 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 related to updated income apportionment by state (including NRG impacts) 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 impacts. See Note 6 to the consolidated financial statements for a discussion of tax benefits related to the investment in NRG.

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 Sept. 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. Value-at-risk, energy trading and hedging information is provided below for informational purposes.

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 commodity contracts, assuming a five-day holding period for electricity and a two-day holding period for natural gas, for the three months ended Sept. 30, 2003, is as follows:


(Millions of	Period Ended		Change from Period Ended
Dollars)	Sept. 30, 2003		June 30, 2003			VaR Limit		Average		High		Low

Electric Commodity Trading (1)	$	0.82	$	(0.08	)	$	6.0	$	0.75	$	1.48	$	0.36
e prime Inc.		0.01		(0.00	)		2.0		0.01		0.03		0.00
e prime Energy Marketing Inc.		0.16		0.09			2.0		0.12		0.21		0.05
XERS Inc.		0.00		(0.13	)		2.0		0.02		0.12		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 and its subsidiaries make wholesale purchases and sales of electricity, natural gas and related energy trading products 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 Sept. 30, 2003, these contracts, with the exception of transmission and natural gas transportation contracts, which meet the definition of a derivative in accordance with SFAS 133, were marked to market. 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.

The changes to the fair value of the energy trading and hedging contracts for the three and nine months ended Sept. 30, 2003 and 2002 were as follows:


	Three months ended Sept. 30, *

(Millions of Dollars)	2003			2002

Fair value of contracts outstanding at June 30	$	3.6		$	9.6
Contracts realized or otherwise settled during the period		(4.0	)		3.9
Fair value of trading contract additions and changes during the period		11.6			1.8

Fair value of contracts outstanding at Sept. 30	$	11.2		$	15.3


	Nine months ended Sept. 30, *

(Millions of Dollars)	2003			2002

Fair value of contracts outstanding at Jan. 1	$	7.8		$	17.9
Contracts realized or otherwise settled during the period		(15.9	)		(11.9	)
Fair value of trading contract additions and changes during the period		19.3			9.3

Fair value of contracts outstanding at Sept. 30	$	11.2		$	15.3


* Excludes NRG.

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

Trading Contracts


	Futures/Forwards

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

NSP-Minnesota		1	$	(306	)				$	(306	)
		2		9,745						9,745
PSCo		1		(440	)					(440	)
		2		1,442						1,442
e prime Inc.		1		685						685
		2		50						50

Total Futures/Forwards Fair Value			$	11,176					$	11,176


	Options

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

PSCo		2	$	12				$	12
e prime Inc.		2		10					10

Total Options
Fair Value			$	22				$	22

Hedge Contracts


	Futures/Forwards

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

NSP-Minnesota		2	$	1,532							$	1,532
PSCo		2		240								240
e prime Inc.		1		(132	)							(132	)
e prime Energy Mktg, Inc.		1		(2,262	)		(625	)				(2,887	)
XERS Inc.		1		(324	)		10					(314	)

Total Futures/Forwards Fair Value			$	(946	)	$	(615	)			$	(1,561	)


	Options

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

NSP-Minnesota		2	$	(6,788	)					$	(6,788	)
NSP-Wisconsin		2		(1,106	)						(1,106	)
PSCo		2		(22,967	)		695				(22,272	)

Total Options Fair Value			$	(30,861	)		695			$	(30,166	)

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


	Nine Months Ended Sept. 30,

(Millions of Dollars)	2003		2002

Net cash provided by operating activities	$	1,003	$	1,499

Cash provided by operating activities decreased for the first nine months of 2003, compared with the first nine months of 2002. The decrease was primarily due to the deconsolidation of NRG, which resulted in no operating cash flows in 2003 compared with approximately $400 million in 2002. In addition, cash flows were lower in 2003 due to higher cash outlays for deferred energy costs in 2003, which will be recovered in future periods, and to the higher collection of prior year unbilled revenue in 2002.


	Nine Months Ended Sept. 30,

(Millions of Dollars)	2003			2002

Net cash used in investing activities	$	(575	)	$	(2,302	)

Cash used in investing activities decreased for the first nine months of 2003, compared with the first nine months of 2002. The decrease is largely due to significant nonregulated capital expenditures and equity investments by NRG in 2002, compared with none in 2003 as a result of the deconsolidation of NRG. In addition, 2003 net cash outflows were partially offset by the proceeds from the sale of Viking Gas in January 2003.


	Nine Months Ended Sept. 30,

(Millions of Dollars)	2003			2002

Net cash provided by (used in) financing activities	$	(232	)	$	1,785

Cash flows related to financing activities decreased from net inflows for the first nine months of 2002 to net outflows in the first nine months of 2003. The decrease is largely due to significant financing requirements for NRG in 2002 compared with none in 2003 as a result of the deconsolidation of NRG.

Credit Facilities and Other Sources of Liquidity

As of Oct. 31, 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	$	40	$	235	$	119	$	354	May-2004
NSP-Wisconsin		$	0	$	0	$	0	$	0	$	0
PSCo		$	350	$	1	$	349	$	29	$	378	May 2004
SPS		$	100	$	3	$	97	$	26	$	123	Feb. 2004
Xcel Energy – Holding Company		$	400	$	1	$	399	$	251	$	650	Nov. 2005

	Total	$	1,125	$	45	$	1,080	$	425	$	1,505

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.

On Oct. 20, 2003, Xcel Energy completed its sale of subsidiary Black Mountain Gas Company to Southwest Gas Corporation. Black Mountain Gas is a natural gas and propane distribution company serving approximately 8,500 natural gas customers and 2,500 propane customers in Arizona. Proceeds from the sale were $24 million.

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 in a private placement to qualified institutional buyers.

NSP-Minnesota

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 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.

NSP-Wisconsin

On Oct. 2, 2003, NSP-Wisconsin issued $150 million of 5.25-percent first mortgage bonds due Oct. 1, 2018, in a private placement to qualified institutional buyers. The proceeds were used to repay short-term debt incurred to pay at maturity $40 million of 5.75 percent first mortgage bonds due Oct. 1, 2003, and to redeem $110 million of 7.25-percent first mortgage bonds. On Oct. 15, 2003, NSP-Wisconsin redeemed the $110 million of 7.25-percent first mortgage bonds, due March 1, 2023.

PSCo

In March 2003, PSCo issued $250 million of 4.875-percent first collateral trust bonds due 2013. The bonds were sold in a private placement 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.

In August 2003, PSCo registered the exchange of $250 million of 4.875-percent first collateral trust bonds due 2013 with the SEC. The bonds were offered in exchange for 4.875 percent first collateral trust bonds due 2013, described above.

In September 2003, PSCo issued $300 million of 4.375-percent first collateral trust bonds due 2008 and $275 million of 5.50-percent first collateral trust bonds due 2014. The proceeds were used for general corporate purposes, including repayment of short-term debt incurred to temporarily fund redemptions discussed previously, and working capital.

SPS

On Oct. 6, 2003, SPS issued $100 million of 6-percent, senior notes due 2033 in a private placement to qualified institutional buyers. On Oct. 15, 2003, the proceeds were used to redeem $100 million, 7.85-percent Trust Originated Preferred Securities of its trust subsidiary, Southwestern Public Service Capital I. The redemption price for each security was $25 principal amount plus a $0.2399 unpaid distribution.

Short-term debt and financial instruments are discussed in Note 9 to the consolidated financial statements.

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 June 30, 2005, up to $2.5 billion of common stock and long-term debt and $1.5 billion of short-term debt at the holding company level. Xcel Energy has issued $2 billion

of long-term debt and common stock.

One of the conditions of the financing order is that Xcel Energy’s ratio of common equity to total capitalization, on a consolidated basis, be at least 30 percent. As of Sept. 30, 2003, after the deconsolidation of NRG following its bankruptcy filing, such common equity ratio was approximately 40.3 percent. If such common equity ratio falls below the 30-percent level, and Xcel Energy is unable to obtain additional relief from the SEC, Xcel Energy may not be able to issue securities, except common stock could be issued even if the common equity ratio is below 30 percent.

Another condition of the financing order is that:

	•		if the security to be issued is rated, it is rated investment grade by at least one nationally recognized rating agency; and

	•		all outstanding securities (except preferred stock) that are rated must be rated investment grade by at least one nationally recognized rating agency.

As of Sept. 30, 2003, Xcel Energy’s senior unsecured debt was rated “BBB-” (CreditWatch positive) by Standard & Poor’s and “Baa3” (stable outlook) by Moody’s Investors Service, which is considered investment grade. These ratings reflect the views of Standard & Poor’s and Moody’s Investors Service. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating company.

Dividend Restrictions

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. At Sept. 30, 2003, Xcel Energy’s retained earnings were approximately $43 million. Xcel Energy has requested authorization from the SEC to pay its third-quarter dividend out of capital and unearned surplus. However no such authorization has yet been received, nor is it assured that the request will be granted.

As of Sept. 30, 2003, Xcel Energy had sufficient retained earnings to declare and pay dividends on its preferred stock. On Oct. 22, 2003, the board of directors declared the dividends on preferred stock to shareholders of record as of Oct. 31, 2003. The preferred dividends were paid on Nov. 10, 2003.

Assuming NRG’s plan of bankruptcy is confirmed by early December and earnings for the remainder of the year are as anticipated, Xcel Energy expects to have sufficient retained earnings to declare and pay the third-quarter common stock dividend (normally paid in October) prior to year end 2003, as well as declare the fourth-quarter common and preferred dividends (normally payable in January 2004).

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.

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 to the consolidated financial statements.

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 discussion of the tax implications of the bankruptcy and settlement agreement in Notes 4 and 6 to the consolidated financial statements. 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 or other arrangements made such that Xcel Energy has no further liability, and any cash collateral posted by Xcel Energy would be returned to it. As of Oct. 31, 2003, no such cash collateral is posted.

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 to the consolidated financial statements 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 nine months ended Sept. 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 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

Xcel Energy

Shareholder Derivative Litigation - On Aug. 15, 2002, a shareholder derivative action was filed in the United States District Court for the District of Minnesota, purportedly on behalf of Xcel Energy, against our directors and certain present and former officers, citing essentially the same circumstances as the class actions described in the securities class action litigation described below and asserting breach of fiduciary duty. This action has been consolidated for pre-trial purposes with the securities class actions. After the filing of this action, two additional derivative actions were filed in the state trial court for Hennepin County, Minnesota (and subsequently consolidated with each other), against essentially the same defendants, focusing on allegedly wrongful energy trading activities and asserting breach of fiduciary duty for failure to establish and maintain adequate accounting controls, abuse of control and gross mismanagement. In each of the derivative cases, the defendants have served motions to dismiss the complaint for failure to make a proper pre-suit demand (or, in the federal court case, to make any pre-suit demand at all) upon our board of directors. On Oct. 10, 2003, oral arguments related to the defendants’ motion to dismiss were presented to the court. The motion was based upon the defendants’ claim that the plaintiffs failed to satisfy the procedural prerequisites for commencing a shareholder derivative suit. The motion was taken under advisement by the court. None of the motions has yet been ruled upon.

Stone/Shaw Litigation - On Oct. 17, 2002, Stone & Webster, Inc. and Shaw Constructors, Inc. filed an action in the United States District Court for the Southern District of Mississippi against Xcel Energy; Wayne H. Brunetti, Chairman, President and Chief Executive Officer; Richard C. Kelly, Vice President and Chief Financial Officer, and NRG and certain NRG subsidiaries. Plaintiffs allege they had a contract with a single purpose NRG subsidiary for the construction of a power generation facility, which was abandoned before completion but after substantial sums had been spent by plaintiffs. They allege breach of contract, breach of an NRG guarantee, breach of fiduciary duty, tortious interference with contract, detrimental reliance, misrepresentation, conspiracy and aiding and abetting, and seek to impose alter ego liability on defendants other than the contracting NRG subsidiary through piercing the corporate veil. The complaint seeks compensatory damages of at least $130 million plus demobilization and cancellation costs and punitive damages at least treble the compensatory damages. Defendants filed motions to dismiss, which were denied, and certain defendants have moved for reconsideration on certain aspects of the motion. The parties have reached a settlement, which is subject to approval by the bankruptcy court in the NRG bankruptcy; further activity in the litigation has been temporarily suspended pending that approval.

Securities Class Action Litigation - On July 31, 2002, a lawsuit purporting to be a class action on behalf of purchasers of our common stock between Jan. 31, 2001 and July 26, 2002, was filed in the United States District Court in Minnesota. The complaint named us; Wayne H. Brunetti, Chairman, President and Chief Executive Officer; Edward J. McIntyre, former Vice President and Chief Financial Officer; and James J. Howard, former Chairman, as defendants. Among other things, the complaint alleged violations of Section 10(b) of the Exchange Act and Rule 10b-5 thereunder related to allegedly false and misleading disclosures concerning various issues, including “round trip’’ energy trades, the existence of cross-default provisions in our and NRG’s credit agreements with lenders, NRG’s liquidity and credit status, the supposed risks to our credit ratings and the status of our internal controls to monitor trading of our power. Thereafter, several additional lawsuits were filed with similar allegations, one of which added claims on behalf of a purported class of purchasers of two series of NRG senior notes issued by NRG in early 2001. The cases have all been consolidated and a consolidated amended complaint has been filed. The amended complaint charges false and misleading disclosures concerning “round trip’’ energy trades and the existence of provisions in our credit agreements with lenders for cross-defaults in the event of a default by NRG and, as to the NRG senior notes, also insufficient disclosures concerning the extent to which NRG’s “fortunes’’ were tied to those of Xcel Energy, especially in the event of a buy-in of NRG public shares. It adds as additional defendants on the claims related to the NRG senior notes Gary R. Johnson, Vice President and General Counsel, Richard C. Kelly, Vice President and Chief Financial Officer, two former executive officers of NRG (David H. Peterson and Leonard A. Bluhm), one current executive Officer of NRG (William T. Pieper) and a former independent director of NRG (Luella G. Goldberg); and, as to the NRG senior notes, it adds claims of similar false and misleading disclosures under Section 11 of the Securities Act of 1933. The defendants filed motions to dismiss all the claims, and the court granted the motions in part and denied them in part on Sept. 30, 2003. In an order dated Sept. 30, 2003, the court granted in part and denied in part the defendants’ motion to dismiss. The court dismissed the claims brought by a sub-class of plaintiffs represented by Catholic Workman. This group consisted of persons who purchased NRG senior notes and alleged false and misleading statements in the registration statement or prospectus under Section 11 of the Securities Act. The court, however, denied the motion with respect to a putative class of plaintiffs consisting of owners of Xcel Energy securities who alleged fraud in violation of Sections 10(b) and 20(a) of the Exchange Act. The defendants expect to file an answer on or about Nov. 14, 2003, and the case is expected to proceed in the normal course as to the claims relating to common stock.

In the normal course of business, various lawsuits and claims have arisen against Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. See Notes 4, 7 and 8 of the consolidated financial statements in this Form 10-Q for further discussion of legal proceedings, including NRG Financial Restructuring and Bankruptcy Filing, 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 filed a suit for damages in state district court based on the same factual allegations. In April 2003, the PUCT approved a recommended proposal for a decision to deny LCEC’s petition. 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 as early as 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. LCEC has appealed to state court the PUCT’s denial of LCEC’s petition.

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 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. By reason of the bankruptcy stay, the court has not ruled on the pending motion. 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. Xcel Energy has reflected in its share of NRG earnings any estimated loss reserves recorded by NRG for these legal contingencies as of their bankruptcy filing date (May 14, 2003). Due to limitations on losses that Xcel Energy can record for NRG, as discussed in Note 5 to the consolidated financial statements, any changes in NRG’s loss reserves recorded by NRG after the bankruptcy date will not affect Xcel Energy’s results.

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 Aug. 15, 2003, the FERC entered two additional orders. One served to uphold the CL&P Contract and purported to require NRG PMI to perform there under, and the other denying NRG PMI’s prior rehearing request. NRG PMI has appealed to the Second Circuit respecting the District Court’s refusal to enjoin the FERC and maintain the restraining order. NRG awaits the Second Circuit’s decision on the above appeal, as well as the 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. Meanwhile, the parties continue to engage in settlement negotiations to all of the foregoing litigation. Xcel Energy has reflected in its share of NRG earnings any estimated loss reserves recorded by NRG for these legal contingencies as of their bankruptcy filing date (May 14, 2003). Due to limitations on losses that Xcel Energy can record for NRG, as discussed in Note 5 to the consolidate financial statements, any changes in NRG’s loss reserves recorded by NRG after the bankruptcy date will not affect Xcel Energy’s results.

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

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

•		Failure to make $10.9 million interest payment due on Sept. 15, 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

•		Failure to make $11.5 million interest payment due on July 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

•		Failure to make $4.8 million interest payment due on Aug. 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

•		Failure to make $4.7 million interest payment due on May 16, 2003

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

•		Failure to make $18.9 million interest payment due on Sept. 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

•		Failure to make $417,558 payment of letter of credit facility fees due July 31, 2003

•		Failure to make $218,000 interest payment on drawn amount due July 1, 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

•		Failure to make $17.5 million principal payment due June 15, 2003

$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.

See Note 9 to the Consolidated Financial Statements for a discussion of Xcel Energy preferred stock arrearages.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

The following Exhibits are filed with this report:

* Indicates incorporation by reference.


* 4.01		Supplemental Indenture dated Aug. 1, 2003, between NSP-Minnesota and BNY Midwest Trust Co., as successor Trustee, creating $200 million principal amount of 2.875 percent first mortgage bonds, series due Aug. 1, 2006 and $175 million principal amount of 4.75 percent first mortgage bonds, series due Aug. 10, 2010. (Filed as Exhibit 4.01 to NSP-Minnesota Form 8-K report (File No. 1-31387) dated Aug. 6, 2003 and incorporated herein by reference.)

* 4.02		Supplemental Indenture dated Sept. 1, 2003 between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating an issue of first mortgage bonds, collateral series N and an issue of first mortgage bonds, collateral series O. (Filed as Exhibit 4.01 to PSCo’s Form 8-K report (File No. 1-3280) dated Sept. 2, 2003 and incorporated herein by reference.)

* 4.03		Supplemental Indenture No. 15 dated Sept. 1, 2003 between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating $300 million principal amount of 4.375 percent first collateral trust bonds, series no. 14 due 2008 and $275 million principal amount of 5.5 percent first collateral trust bonds, series no. 15 due 2014. (Filed as Exhibit 4.02 to PSCo’s Form 8-K report (File No. 1-3280) dated Sept. 2, 2003 and incorporated herein by reference.)


4.04		Third Supplemental Indenture dated Oct. 1, 2003 between SPS and JPMorgan Chase Bank, as successor Trustee, creating $100 million principal amount of series C senior notes, 6 percent due 2033.

4.05		Supplemental Trust Indenture dated Sept. 1, 2003 between NSP-Wisconsin and U.S. Bank National Association, as Trustee, creating $150 million principal amount of 5.25 percent first mortgage bonds, series due Oct. 1, 2018

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 Sept. 30, 2003, or between Sept. 30, 2003, and the date of this report:

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

Sept. 3, 2003 (filed Sept. 4, 2003) – Items 5 and 7 Other Events and Financial Statements and Exhibits – Re: Materials presented at Lehman Energy Conference on Sept. 4, 2003.

Sept. 24, 2003 (filed Sept. 24, 2003) – Items 5 and 7 Other Events and Financial Statements and Exhibits – Re: Announcement of settlement agreement with the Minnesota Attorney General and Minnesota Department of Commerce in their investigation into power outage reporting, and reaffirm earnings guidance for continuing operations for 2003.

Sept. 29, 2003 (filed Sept. 29, 2003) – Item 5 Other Events – Re: Excerpts of offering circular for the issue of long-term debt by NSP-Wisconsin.

Oct. 22, 2003 (filed Oct. 22, 2003) – Item 5 Other Events – Re: Richard C. Kelly announced as president and chief executive officer and Benjamin G.S. Fowke named as chief financial officer.

Oct. 23, 2003 (filed Oct. 23, 2003) – Items 7 and 12 Exhibits and Results of Operations and Financial Statements – Re: Earnings release of Xcel Energy for the third quarter of 2003.

Oct. 24, 2003 (filed Oct. 24, 2003) – Items 7 and 12 Exhibits and Results of Operations and Financial Statements – Re: Materials presented at Edison Electric Institute Financial Conference on Oct. 28, 2003.