Xcel Energy (XEL) 10-Q 2001 Q3 Quarterly report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For Quarter Ended Sept. 30, 2001

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, Minn. (Address of principal executive offices)	55402 (Zip Code)

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

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

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

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

Class	Outstanding at Oct. 31, 2001
Common Stock, $2.50 par value	345,529,116 shares

TABLE OF CONTENTS

Letter from Arthur Andersen LLP

Stmt pursuant to Private Litigation Reform Act

PART 1.     FINANCIAL INFORMATION

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

			Three Months Ended						Nine Months Ended
			Sept. 30						Sept. 30
			2001			2000			2001			2000
			(Unaudited)
			(Thousands of dollars, except per share data)
Operating revenues:
	Electric utility		$	1,818,812		$	1,666,914		$	5,010,201		$	4,162,930
	Gas utility			216,589			176,914			1,577,159			895,956
	Electric and gas trading			688,076			567,911			2,524,392			1,163,368
	Nonregulated and other			928,976			585,333			2,384,562			1,509,090
	Equity earnings from investments in affiliates			111,021			95,995			196,285			166,515
		Total operating revenues		3,763,474			3,093,067			11,692,599			7,897,859
Operating expenses:
	Electric fuel and purchased power — utility			940,161			790,809			2,547,256			1,804,378
	Cost of gas sold and transported — utility			135,734			84,194			1,199,888			542,920
	Electric and gas trading costs			678,735			555,001			2,433,059			1,132,769
	Cost of sales — nonregulated and other			450,204			270,257			1,273,979			690,698
	Other operating and maintenance expenses — utility			366,344			327,359			1,095,295			1,029,213
	Other operating and maintenance expenses — nonregulated			226,162			167,371			606,929			445,959
	Depreciation and amortization			250,578			201,073			684,963			583,570
	Taxes (other than income taxes)			53,894			90,062			236,395			271,991
	Special charges (see Note 2)			—			201,482			23,018			201,482
		Total operating expenses		3,101,812			2,687,608			10,100,782			6,702,980
Operating income				661,662			405,459			1,591,817			1,194,879
Other income (expense):
	Minority interest			(39,699	)		(19,025	)		(58,260	)		(28,752	)
	Other income — net			22,577			(5,203	)		46,344			789
		Total other income (expense)		(17,122	)		(24,228	)		(11,916	)		(27,963	)
Interest charges and financing costs:
	Interest charges — net of amounts capitalized			212,037			175,881			574,353			487,115
	Distributions on redeemable preferred securities of subsidiary trusts			9,700			9,700			29,100			29,100
		Total interest charges and financing costs		221,737			185,581			603,453			516,215
Income before income taxes and extraordinary items				422,803			195,650			976,448			650,701
Income taxes				149,900			97,734			326,378			242,714
Income before extraordinary items				272,903			97,916			650,070			407,987
Extraordinary items (see Note 4)				—			(5,302	)		—			(18,960	)
Net income				272,903			92,614			650,070			389,027
Dividend requirements on preferred stock				(1,060	)		(1,060	)		(3,180	)		(3,181	)
Earnings available for common shareholders			$	271,843		$	91,554		$	646,890		$	385,846
Weighted average common shares outstanding:
Basic				343,770			338,495			342,378			337,287
Diluted				344,385			338,876			343,188			337,450
Earnings per share — basic before extraordinary items			$	0.79		$	0.29		$	1.89		$	1.20
Extraordinary items (see Note 4)				—			(0.02	)		—			(0.06	)
Earnings per share — basic			$	0.79		$	0.27		$	1.89		$	1.14
Earnings per share — diluted before extraordinary items			$	0.79		$	0.29		$	1.88		$	1.20
Extraordinary items (see Note 4)				—			(0.02	)		—			(0.06	)
Earnings per share — diluted			$	0.79		$	0.27		$	1.88		$	1.14

See Notes to Consolidated Financial Statements

1

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

				Nine Months Ended
				Sept. 30
				2001			2000
				(Unaudited)
				(Thousands of dollars)
Operating activities:
	Net income			$	650,070		$	389,027
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			715,493			613,846
		Nuclear fuel amortization			31,843			32,937
		Deferred income taxes			(34,193	)		16,001
		Amortization of investment tax credits			(9,684	)		(10,431	)
		Allowance for equity funds used during construction			(6,373	)		695
		Undistributed equity in earnings of unconsolidated affiliates			(170,900	)		(151,067	)
		Special charges — not requiring (using) cash			23,018			99,830
		Conservation incentive accrual adjustment			(32,218	)		19,966
		Unrealized loss on energy contracts			13,942			0
		Extraordinary Item			0			18,960
		Change in accounts receivable			155,090			(188,014	)
		Change in inventories			(123,826	)		(54,988	)
		Change in other current assets			354,756			(111,661	)
		Change in accounts payable			(495,896	)		271,928
		Change in other current liabilities			258,220			60,695
		Change in other assets and liabilities			8,206			(32,911	)
			Net cash provided by operating activities		1,337,548			974,813
Investing activities:
	Nonregulated capital expenditures and asset acquisitions				(3,901,094	)		(2,064,006	)
	Utility capital/construction expenditures				(753,572	)		(617,275	)
	Allowance for equity funds used during construction				6,373			(695	)
	Investments in external decommissioning fund				(46,865	)		(35,364	)
	Equity investments, loans, deposits and sales of nonregulated projects				82,194			(81,425	)
	Other investments — net				(10,384	)		(8,359	)
			Net cash used in investing activities		(4,623,348	)		(2,807,124	)
Financing activities:
	Short-term borrowings — net				737,880			331,517
	Proceeds from issuance of long-term debt				2,854,213			2,856,155
	Repayment of long-term debt, including reacquisition premiums				(422,936	)		(1,363,539	)
	Proceeds from issuance of common stock				108,609			97,875
	Proceeds from the NRG stock offering				474,348			453,705
	Dividends paid				(388,491	)		(419,912	)
			Net cash provided by financing activities		3,363,623			1,955,801
Effect of exchange rate changes on cash and cash equivalents					8,173			0
	Net increase in cash and cash equivalents				85,996			123,490
	Cash and cash equivalents at beginning of period				216,491			139,731
	Cash and cash equivalents at end of period			$	302,487		$	263,221

See Notes to Consolidated Financial Statements

2

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

			Sept. 30,			Dec. 31,
			2001			2000
			(Unaudited)
			(Thousands of dollars)
ASSETS
Current assets:
	Cash and cash equivalents		$	302,487		$	216,491
	Accounts receivable — net of allowance for bad debts of $70,625 and $41,350, respectively			1,070,534			1,282,241
	Accrued unbilled revenues			488,077			683,266
	Materials and supplies inventories — at average cost			350,687			286,453
	Fuel inventory — at average cost			226,883			148,305
	Gas inventories — replacement cost in excess of LIFO: $36,829 and $106,790, respectively			69,467			46,075
	Recoverable purchased gas and electric energy costs			54,963			283,167
	Current portion of notes receivable			108,243			7,483
	Derivative instruments valuation — at market			87,109			0
	Deposits and restricted cash			169,399			24,862
	Prepayments and other			224,424			149,731
		Total current assets		3,152,273			3,128,074
Property, plant and equipment, at cost:
	Electric utility plant			15,883,465			15,304,407
	Gas utility plant			2,452,670			2,376,868
	Nonregulated property and other			10,611,773			5,641,968
	Construction work in progress			588,704			622,494
		Total property, plant and equipment		29,536,612			23,945,737
	Less: accumulated depreciation			(9,341,673	)		(8,759,322	)
	Nuclear fuel — net of accumulated amortization of $999,771 and $967,927, respectively			85,078			86,499
		Net property, plant and equipment		20,280,017			15,272,914
Other assets:
	Investments in unconsolidated affiliates			1,341,097			1,459,410
	Notes receivable, including amounts from affiliates of $155,884 and $76,918, respectively			779,520			92,074
	Nuclear decommissioning fund and other investments			736,086			732,908
	Regulatory assets			475,298			524,261
	Derivative instruments valuation — at market			167,372			0
	Prepaid pension asset			348,888			225,134
	Other			465,735			334,068
		Total other assets		4,313,996			3,367,855
		Total Assets	$	27,746,286		$	21,768,843
LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	851,275		$	603,611
	Short-term debt			2,210,706			1,475,072
	Accounts payable			1,325,502			1,608,989
	Taxes accrued			461,031			236,837
	Dividends payable			130,513			128,983
	Derivative instruments valuation — at market			125,101			0
	Other			612,893			618,316
		Total current liabilities		5,717,021			4,671,808
Deferred credits and other liabilities:
	Deferred income taxes			2,089,046			1,794,193
	Deferred investment tax credits			187,904			198,108
	Regulatory liabilities			466,437			494,566
	Derivative instruments valuation — at market			84,368			0
	Benefit obligations and other			786,041			588,288
		Total deferred credits and other liabilities		3,613,796			3,075,155
Minority interest in subsidiaries				651,122			277,335
Capitalization:
	Long-term debt			10,959,875			7,583,441
	Mandatorily redeemable preferred securities of subsidiary trusts			494,000			494,000
	Preferred stockholders’ equity — authorized 7,000,000 shares of $100 par value; outstanding shares: 1,049,800			105,320			105,320
	Common stockholders’ equity — authorized 1,000,000,000 shares of $2.50 par value; outstanding shares: 2001, 344,915,088; 2000, 340,834,147			6,205,152			5,561,784
Commitments and Contingent Liabilities (see Note 5)
		Total Liabilities and Equity	$	27,746,286		$	21,768,843

See Notes to Consolidated Financial Statements

3

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

													Accumulated
													Other			Total
							Retained			Shares Held			Comprehensive			Stockholders’
		Par Value		Premium			Earnings			by ESOP			Income			Equity
		(Unaudited)
		(Thousands of dollars)
Three Months Ended Sept. 30, 2001 and 2000
Balance at June 30, 2000		$	845,642	$	2,555,398		$	2,298,337		$	(8,249	)	$	(140,681	)	$	5,550,447
Net income								92,614									92,614
Currency translation adjustments														(48,129	)		(48,129	)
Comprehensive income for the period																	44,485
Dividends declared:
	Cumulative preferred stock of Xcel Energy							(1,060	)								(1,060	)
	Common stock							(114,561	)								(114,561	)
Issuances of common stock — net			4,582		36,676												41,258
Other			1		(1,989	)		(46	)								(2,034	)
ESOP loans, net of repayment(a)											(18,365	)					(18,365	)
Balance at Sept. 30, 2000		$	850,225	$	2,590,085		$	2,275,284		$	(26,614	)	$	(188,810	)	$	5,500,170
Balance at June 30, 2001		$	860,211	$	2,924,429		$	2,401,727		$	(21,502	)	$	(141,000	)	$	6,023,865
Net income								272,903									272,903
Currency translation adjustments														39,066			39,066
Net gains or (losses) on derivatives (see Note  8)														(26,710	)		(26,710	)
Comprehensive income for the period																	285,259
Dividends declared:
	Cumulative preferred stock of Xcel Energy							(1,060	)								(1,060	)
	Common stock							(129,343	)								(129,343	)
Issuances of common stock — net			2,076		22,894												24,970
Other								17									17
Repayment of ESOP loans(a)											1,444						1,444
Balance at Sept. 30, 2001		$	862,287	$	2,947,323		$	2,544,244		$	(20,058	)	$	(128,644	)	$	6,205,152
Nine Months Ended Sept. 30, 2001 and 2000
Balance at Dec. 31, 1999		$	838,193	$	2,288,254		$	2,253,800		$	(11,606	)	$	(78,421	)	$	5,290,220
Net income								389,027									389,027
Currency translation adjustments														(110,389	)		(110,389	)
Comprehensive income for the period																	278,638
Dividends declared:
	Cumulative preferred stock of Xcel Energy							(3,181	)								(3,181	)
	Common stock							(364,319	)								(364,319	)
Issuances of common stock — net			12,032		87,839												99,871
Tax benefit from stock options exercised					47												47
Other					(1,988	)		(43	)								(2,031	)
Gain recognized from NRG stock offering					215,933												215,933
ESOP loans, net of repayments(a)											(15,008	)					(15,008	)
Balance at Sept. 30, 2000		$	850,225	$	2,590,085		$	2,275,284		$	(26,614	)	$	(188,810	)	$	5,500,170
Balance at Dec. 31, 2000		$	852,085	$	2,607,025		$	2,284,220		$	(24,617	)	$	(156,929	)	$	5,561,784
Net income								650,070									650,070
Currency translation adjustments														17,604			17,604
Cumulative effect of accounting change — SFAS 133														(28,780	)		(28,780	)
Net gains or (losses) on derivatives (see Note  8)														39,461			39,461
Comprehensive income for the period																	678,355
Dividends declared:
	Cumulative preferred stock of Xcel Energy							(3,180	)								(3,180	)
	Common stock							(386,840	)								(386,840	)
Issuances of common stock — net			10,202		98,407												108,609
Other								(26	)								(26	)
Gain recognized from NRG stock offering					241,891												241,891
Repayment of ESOP loans(a)											4,559						4,559
Balance at Sept. 30, 2001		$	862,287	$	2,947,323		$	2,544,244		$	(20,058	)	$	(128,644	)	$	6,205,152

(a)  Did not affect cash flows

See Notes to Consolidated Financial Statements

4

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, 2001, and Dec. 31, 2000, the results of its operations and stockholders’ equity for the three and nine months ended Sept. 30, 2001 and 2000, and its cash flows for the nine months ended Sept. 30, 2001 and 2000. Due to the seasonality of Xcel Energy’s electric and gas sales and variability of nonregulated operations, quarterly and year-to-date 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, 2000. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K.

     We reclassified certain items in the 2000 income statement and the 2000 balance sheet to conform to the 2001 presentation. These reclassifications had no effect on net income or earnings per share. Reported amounts for periods prior to the merger have been restated to reflect the merger as if it had occurred as of Jan. 1, 2000.

1.     Merger to Create Xcel Energy

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

     Xcel Energy directly owns six utility subsidiaries that serve electric and natural gas customers in 12 states. These six utility subsidiaries are Northern States Power Co., a Minnesota corporation (NSP-Minnesota), Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin), Public Service Co. of Colorado (PSCo), Southwestern Public Service Co. (SPS), Black Mountain Gas Co. (BMG) and Cheyenne Light, Fuel and Power Co. (Cheyenne). Their service territories include portions of Arizona, Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Wisconsin and Wyoming. Xcel Energy’s regulated businesses also include Viking Gas Transmission Co. and WestGas InterState Inc. (WGI), both interstate natural gas pipeline companies.

     Xcel Energy also owns or has an interest in a number of nonregulated businesses, the largest of which is NRG Energy, Inc., a publicly traded independent power producer. At Sept. 30, 2001, Xcel Energy indirectly owned approximately 74 percent of NRG. Xcel Energy owned 100 percent of NRG until the second quarter of 2000, when NRG completed its initial public offering and 82 percent until a secondary offering was completed in March 2001.

     In addition to NRG, Xcel Energy’s nonregulated subsidiaries include Utility Engineering (engineering, construction and design), Seren Innovations, Inc. (broadband telecommunications services), e prime inc. (natural gas marketing and trading), Planergy International, Inc. (energy management, consulting and demand-side management services), Eloigne Company (investments in rental housing projects that qualify for low-income housing tax credits), Independent Power International (IPI) and Xcel Argentina (both international independent power producers).

5

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Consistent with pooling accounting requirements, during 2000, Xcel Energy expensed all merger-related costs as discussed in Note 2. An allocation of merger costs was made to utility operating companies using a basis consistent with prior regulatory filings, in proportion to expected merger savings for each company and consistent with service company cost allocation methodologies utilized under PUHCA requirements.

2.     Special Charges

     Merger Related —In 2000, Xcel Energy expensed pretax special charges totaling $241 million. These special charges reduced Xcel Energy’s 2000 earnings by 52 cents per share. Of these special charges $201 million, or 43 cents per share, was expensed during the third quarter of 2000, and $40 million, or 9 cents per share, was expensed during the fourth quarter of 2000.

     The pretax charges included $52 million of one-time transaction-related costs incurred in connection with the merger of NSP and NCE, $147 million of pretax charges pertaining to incremental costs of transition and integration activities associated with merging NSP and NCE to begin operations as Xcel Energy, and $42 million of asset impairments and other costs resulting from the post-merger strategic alignment of Xcel Energy’s nonregulated businesses.

     The transition costs included costs for severance and related expenses associated with staff reductions of 721 employees, 686 of whom were released through Sept. 30, 2001.

     A portion of these special charges was accrued as a liability at Dec. 31, 2000. The following table summarizes the change in the liability for special charges during the first nine months of 2001.

				Accrual		Payments
		Dec. 31, 2000		Adjustments		Against			Sept. 30, 2001
		Liability*		Expensed		Liability			Liability*
		Millions of dollars
Employee separation and other related costs		$	48		—	$	(36	)	$	12
Regulatory transition costs			5		—		(2	)		3
Other transition and integration costs			2		—		(2	)		—
	Total accrued merger costs	$	55		—	$	(40	)	$	15

*  Reported on the balance sheet in other current liabilities.

     Postemployment Benefits —PSCo adopted accrual accounting for postemployment benefits under Statement of Financial Accounting Standards (SFAS) No. 112 — “Employer’s Accounting for Postemployment Benefits” in 1994. The costs of these benefits were historically recorded on a pay-as-you-go basis and, accordingly, PSCo recorded a regulatory asset in anticipation of obtaining future rate recovery of these transition costs. PSCo requested approval to recover its Colorado retail natural gas jurisdictional portion in a 1996 retail rate case and its retail electric jurisdictional portion in the electric earnings test filing for 1997.

     In the 1996 rate case, the Colorado Public Utility Commission (CPUC) allowed recovery of postemployment benefit costs on an accrual basis, but denied PSCo’s request to amortize the transition costs as a regulatory asset. PSCo appealed this decision to the Denver District Court. In 1998, the CPUC deferred the final determination of the regulatory treatment of the electric jurisdictional costs pending the outcome of PSCo’s appeal on the natural gas rate case. On Dec. 16, 1999, the Denver District Court affirmed the decision by the CPUC. On July 2, 2001, the Colorado Supreme Court affirmed the District Court decision. Accordingly, PSCo wrote off $23 million, or 4 cents per share, of deferred postemployment benefit costs during the second quarter of 2001.

6

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

3.     Business Developments

     Completed NRG Asset Acquisitions

     Audrain —In June 2001, NRG purchased a 640-megawatt, natural gas-fired power plant in Audrain County, Missouri, from Duke Energy North America LLC.

     Brazos Valley —In June 2001, NRG closed on the construction financing for a 633-megawatt, gas-fired power plant in Texas that NRG will build, operate and manage. At the time of the closing, NRG also became the 100-percent owner of the project by purchasing STEAG Power LLC’s 50-percent interest in the project. NRG estimates that its investment in the project will total approximately $170 million. NRG expects the project to begin commercial operation in February 2003.

     Conectiv —In June 2001, NRG purchased 1,081 megawatts of interests in power generation plants from a subsidiary of Conectiv for approximately $644 million. NRG acquired a 100-percent interest in the 784-megawatt, coal-fired Indian River Generating Station, located in Delaware, and in the 170-megawatt, oil-fired Vienna Generating Station, located in Maryland. In addition, NRG acquired 64 megawatts of the 1,711-megawatt, coal-fired Conemaugh Generating Station and 63 megawatts of the 1,711-megawatt, coal-fired Keystone Generating Station, both located near Pittsburgh, Penn.

     Vattenfall —In June 2001, NRG acquired Vattenfall’s interests in three South American projects. Those projects consist of Compania Boliviana de Energia Electrica S.A. — Bolivian Power Company Ltd. (COBEE) and Compania Electrica Central Bulo Bulo S.A., both in Bolivia, and Itiquira Energetica S.A. in Brazil. In addition, NRG acquired the ownership interest of Inepar Energia S.A. (Inepar) in the Itiquira project. NRG now owns 98.9 percent of COBEE, 60 percent of Bulo Bulo and 99 percent of the common shares of Itiquira. COBEE, with 220 megawatts of predominantly hydroelectric generation, is the second largest electric generator in Bolivia. Bulo Bulo is an 88-megawatt, natural gas-fired facility in Bolivia. Itiquira is a 156-megawatt hydroelectric project in the advanced stage of construction in Brazil. Full commercial operation of Itiquira is expected in March 2002.

     PowerGen —In June 2001, NRG purchased a 389-megawatt, gas-fired power plant and a 116-megawatt, thermal power plant, both of which are located in Hungary, from PowerGen. In April 2001, NRG also purchased PowerGen’s interest in Saale Energie GmbH and MIBRAG BV. By acquiring PowerGen’s interest in Saale Energie, NRG increased its ownership interest in the 960-megawatt, coal-fired Schkopau power station, located in Germany, from 200 megawatts to 400 megawatts. By acquiring PowerGen’s interest in MIBRAG, consisting primarily of two lignite mines and three power stations in Germany, NRG increased its ownership of MIBRAG from 33.3 percent to 50 percent. NRG paid approximately $190 million to PowerGen for all of these interests.

     Hsin Yu —In July 2001, NRG acquired approximately 60 percent of Hsin Yu Energy Development Co. Ltd, a Taiwan company. Hsin Yu currently owns a 170-megawatt, cogeneration facility, Hsinchu Phase I. Hsin Yu is developing a 245-megawatt expansion of the Hsinchu facility and a new 490-megawatt greenfield project in Taiwan.

     Kondapalli —In July 2001, NRG acquired a 30 percent ownership in the Kondapalli Power station from TXU. The 360-megawatt gas and oil-fired generating facility is located in India.

     Indeck —In August 2001, NRG acquired an approximately 2,255-megawatt portfolio of operating projects and projects in advanced development that are located in Illinois and upstate New York from Indeck Energy Services, Inc. Approximately 402 megawatts are currently in operation and NRG expects that an additional $1.3 billion will be required to complete construction of the projects.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     McClain —In August 2001, NRG acquired Duke Energy’s 77-percent interest in the 520-megawatt, natural gas-fired McClain Energy Generating Facility, located in Oklahoma, for approximately $277 million. The Oklahoma Municipal Power Authority owns the remaining 23-percent interest.

     Meriden —In August 2001, NRG acquired a 540 megawatt, natural gas-fired generation facility being developed in Connecticut. NRG estimates it will cost approximately $384 million to complete construction of the plant, which has a planned commercial operation date of June 2003.

     Saguaro —In September 2001, NRG acquired a 50 percent interest in the Saguaro Generating Station from Edison Mission Energy. The Saguaro Generating Station, located near Las Vegas, Nevada, is a 105-megawatt, combined cycle facility that provides electricity and steam to Nevada Power and two commercial operations.

     Termorio —In September 2001, NRG acquired a 50 percent interest in Termorio SA, a 1,040-megawatt gas-fired co-generation facility currently under construction from Petroleos Brasileiros SA located in Brazil.

     Pending NRG Asset Acquisitions

     Conectiv —In June 2001, NRG extended purchase agreements with a subsidiary of Conectiv to acquire 794 megawatts of coal and oil-fired electric generating capacity and other assets in New Jersey and Pennsylvania, including an additional 66 megawatts of the Conemaugh Generating Station and an additional 42 megawatts of the Keystone Generating Station. NRG will pay approximately $180 million for these assets. NRG expects the acquisition to close in the fourth quarter of 2001 following regulatory approval.

     Narva Power —In August 2000, NRG signed an agreement with Eesti Energia, the Estonian state-owned electric utility, to purchase for approximately $72 million a 49 percent stake in Narva Power, the owner and operator of the oil shale-fired Eesti and Balti power plants, located near Narva, Estonia. The plants have a combined capacity of approximately 2,700 megawatts. NRG is working to close the acquisition in the fourth quarter of 2001.

     In August 2001, NRG signed an agreement to acquire a 50-percent interest in the Commonwealth Atlantic 375-megawatt, gas and oil-fired generating station from Edison Mission Energy. The Commonwealth Atlantic facility is located near Chesapeake, Virginia. In addition, NRG will also acquire a 50-percent interest in the James River 110-megawatt, coal-fired generating facility located in Hopewell, Virginia and Enron North America’s 15-percent interest in the Saguaro Generating Station.

     Other Developments

     Yorkshire Power —During February 2001, Xcel Energy reached an agreement to sell the majority of its investment in Yorkshire Power to Innogy Holdings plc. As a result of this sales agreement, Xcel Energy did not record any equity earnings from Yorkshire Power after January 2001. In April 2001, Xcel Energy closed the sale of Yorkshire Power. Xcel Energy retains an interest of approximately 5 percent in Yorkshire Power to comply with pooling-of-interests accounting requirements associated with the merger of NSP and NCE in 2000. Xcel Energy received approximately $366 million for the sale, which approximated the book value of Xcel Energy’s investment. Xcel Energy used the proceeds of the sale to pay down short-term debt and eliminate the need for an equity issuance planned for the second half of 2001.

     Fort St. Vrain Repowering —In June 2001, PSCo completed the six-year, $283-million repowering of the Fort St. Vrain Generating Station in Colorado. The phased repowering over the past several years has added 720 megawatts of electric supply to PSCo’s system. Fort St. Vrain utilizes three combined-cycle turbine generators of approximately 140 megawatts, powered by natural gas. After producing electricity in the newer turbine generators, waste heat is captured for steam production for the plant’s original 300-megawatt generator. Fort St. Vrain, formerly a nuclear power plant, was dismantled and decommissioned as a nuclear facility in August 1996.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Wind Power —In April 2001, NSP-Minnesota selected a developer to add more wind-generated electricity to its portfolio. Chanarambie Power Partners, LLC, will build wind turbines in southwestern Minnesota to add another 80 megawatts of wind power. Execution of this contract will mean that NSP-Minnesota has fulfilled a 1994 Minnesota legislative requirement to develop 425 megawatts of Minnesota wind energy relating to the authorization to store spent nuclear fuel in dry casks outside the Prairie Island nuclear plant. Xcel Energy is also developing additional wind power projects in Texas, Wyoming, Colorado and New Mexico.

     Independent Transmission Company (ITC) —On Sept. 28, 2001, Xcel Energy and several other electric utilities applied to the Federal Energy Regulatory Commission (FERC) to integrate operations of their electric transmission systems into a single system through the formation of TRANSLink Transmission Co. LLC, a for-profit, transmission-only company. The utilities will participate in TRANSLink through a combination of divestiture, leases and operating agreements. The applicants are: Alliant Energy’s Iowa companies (IES Utilities Inc. and Interstate Power Co.), Corn Belt Power Cooperative, MidAmerican Energy Co., Nebraska Public Power District, Omaha Public Power District and Xcel Energy. The participants asked the FERC to expedite consideration of their application, requesting action by early 2002. The TRANSLink proposal is subject to receipt of all required federal and state regulatory approvals.

     TRANSLink’s business will be the development, maintenance and operation of a transmission system capable of meeting the increasing energy demands both locally and throughout the region. TRANSLink will oversee 26,000 miles of transmission lines, linking generators producing 35,000 megawatts of electric power to approximately 6.9 million customers in 14 states, making it one of the largest transmission companies in the nation.

     The participants believe TRANSLink is the most cost-efficient option available to manage transmission and to comply with regulations issued by the FERC in 1999 (known as Order No. 2000) that require investor-owned electric utilities to transfer operational control of their transmission system to an independent regional transmission organization (RTO). TRANSLink will comply with these regulations by operating independently of both buyers and sellers in the electricity market, including the applicant utilities. Its independent board of directors will also be responsible for maximizing the value of the transmission system and increasing the efficiency of its operations. Other options for complying with the FERC regulations leave ownership with the utilities, but do not allow the owners any operational control.

     Under the proposal, TRANSLink will be responsible for planning, managing and operating both local and regional transmission assets. Transmission service pricing will continue to be regulated by the FERC, but construction and permitting approvals will continue to rest with regulators in the states served by TRANSLink. The participants have also entered into a memorandum of understanding with the Midwest Independent Transmission Operator, Inc. (MISO) in which they agree that TRANSLink will contract with MISO for certain other required RTO functions and services.

4.     Restructuring and Regulation

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

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XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

mortgage bonds were defeased to facilitate the legal separation of generation, transmission and distribution assets, which was expected to eventually occur in 2001 under restructuring requirements.

     In March 2001, the state of New Mexico enacted legislation that delayed customer choice until 2007 and amended the Electric Utility Restructuring Act of 1999. SPS has requested recovery of its costs incurred to prepare for customer choice in New Mexico. If the request is not approved, SPS has requested authority to establish a regulatory asset in the amount of its transition costs and to continue deferral of such costs until future recovery is determined in a ratemaking proceeding. A decision on this and other matters is pending before the New Mexico Public Regulation Commission (NMPRC).

     In June 2001, the Governor of Texas signed legislation postponing the deregulation and restructuring of SPS until 2007. This legislation amended the 1999 legislation, Senate Bill No. 7 (SB-7), which provided for retail electric competition beginning January 2002. Under the newly-adopted legislation, prior PUCT orders issued in connection with the restructuring of SPS will be considered null and void. SPS’ restructuring and rate unbundling proceedings in Texas have been terminated. In addition, under the new legislation, SPS is entitled to recover all reasonable and necessary expenditures made or incurred before Sept. 1, 2001, to comply with SB-7. As required, SPS plans to file an application during the fourth quarter of 2001, requesting a rate rider to recover these costs incurred preparing for customer choice.

     As a result of these recent legislative developments, SPS reapplied the provisions of SFAS 71 for its generation business during the second quarter of 2001. More than 95 percent of SPS’ retail electric revenues are from operations in Texas and New Mexico. Because of the delays to electric restructuring passed by Texas and New Mexico, SPS’ previous plans to implement restructuring, including the divestiture of generation assets, have been abandoned. Accordingly, SPS will now continue to be subject to rate regulation under traditional cost of service regulation, consistent with its past accounting and ratemaking practices. At this time, management is uncertain whether restructuring will be completed in 2007 or later and what the transition plan to competition will be at that time. SPS has not restored regulatory assets or capitalized defeasance costs previously written off in 2000. Due to the regulatory uncertainty regarding the recovery of these costs in future rates, SPS has delayed the restoration of regulatory assets until specific regulatory recovery is determined. Consequently, SPS has not recognized any earnings impact for financial reporting purposes as a result of its reapplication of SFAS 71 through Sept. 30, 2001. However, future regulatory developments may create earnings increases (should additional cost recovery be provided) or decreases (should deferred costs not be fully recovered).

     As of Sept. 30, 2001, SPS had incurred approximately $45 million of restructuring costs, including $8 million of debt defeasance costs allocated to the generation business, which was expensed as an extraordinary item in the third quarter of 2000 and $37 million of other restructuring costs, which have been deferred based on anticipated future recovery in jurisdictional rates. SPS anticipates regulatory determinations for restructuring cost recovery in late 2001 or early 2002.

     Cheyenne Purchased Power Costs —For 37 years, Cheyenne purchased all electric supply requirements from PacifiCorp. Cheyenne’s most recent full-requirements power purchase agreement with PacifiCorp expired on Feb. 24, 2001. During 2000, as contract details for a new agreement were being finalized between Cheyenne and PacifiCorp, energy supply conditions and market prices in the western United States dramatically changed. Cheyenne was unable to execute a new agreement with PacifiCorp for the prices and terms it had been negotiating. Consequently, since Feb. 24, 2001, PSCo has been currently supplying Cheyenne’s power requirements.

     In March 2001, Cheyenne requested an increase in retail electric rates to provide for recovery of increasing power costs. As a result of the significant increase in electric energy costs since late February 2001, Cheyenne under recovered its costs under its electric cost adjustment (ECA) mechanism. On May 25, 2001, the Wyoming Public Service Commission (WPSC) approved a Stipulation Agreement between Cheyenne

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XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

and intervenors in connection with a proposed increase in rates charged to Cheyenne’s retail customers to recover increased power costs.

     The Stipulation Agreement provides for an ECA rate structure with a fixed energy supply rate for Cheyenne’s customers through 2003 (an estimated combined capacity and energy rate of approximately $54 per megawatt-hour); the continuation of the ECA with certain modifications, including the amortization through December 2005 of unrecovered costs incurred during 2001 up to the agreed upon fixed supply rates; and an agreement that Cheyenne’s energy supply needs will be provided, in whole or in part, by PSCo in accordance with wholesale tariff rates to be approved by the FERC. The estimated retail rate increases under the Stipulation are expected to provide recovery of an additional $18 million (compared with prior rate levels) through the remainder of 2001 and a total of $28 million for each of the years 2002 and 2003. In 2004 and 2005, Cheyenne will return to requesting recovery of its actual costs incurred plus the outstanding balance of any deferral from earlier years. New cost levels consistent with the Stipulation Agreement have been reflected in Cheyenne’s expenses effective June 1, 2001, and in deferred costs based on current ECA recovery levels, reflect retroactive accrual adjustments back to the date of the increase in costs on Feb. 25, 2001. The power costs underlying the Stipulation Agreement are based on wholesale tariff rates approved by the FERC in August 2001.

5.     Commitments and Contingent Liabilities

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

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

     The circumstances set forth in Notes 14 and 15 to Xcel Energy’s financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2000, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident, except for the following updated developments.

     California Power Market —NRG’s California generation assets consist primarily of its interests in the Crockett and Mt. Poso facilities and a 50 percent interest in West Coast Power LLC, formed in 1999 with Dynegy Inc. The West Coast Power facilities sold power through the California Power Exchange (PX) and the California Independent System Operator (ISO) to Pacific Gas and Electric Co. (PG&E), Southern California Edison Co. (SCE) and San Diego Gas and Electric Co. (SDG&E). Currently, the West Coast Power facilities sell power through the California ISO to the California Department of Water Resources (CDWR). Crockett, Mt.Poso and certain other NRG California facilities also sell directly to PG&E, SCE and SDG&E. The combination of rising wholesale electric prices, increases in the cost of natural gas, the scarcity of hydroelectric power and regulatory limitations on the rates that PG&E and SCE may charge their retail customers caused both PG&E and SCE to default in their payments to the California PX, the California ISO and other suppliers, including NRG. In March 2001, the California PX filed for Chapter 11 bankruptcy. In April 2001, PG&E filed for Chapter 11 bankruptcy.

     In March 2001, affiliates of West Coast Power entered into a contract with the CDWR in which the affiliates agreed to sell up to 1,000 megawatts to the CDWR for the remainder of 2001 and up to 2,300 megawatts from January 2002 through December 2004, any of which may be resold by the CDWR to utilities

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

such as SCE, PG&E and SDG&E. The ability of the CDWR to make future payments is subject to the CDWR having a continued source of funding, whether from legislative or other emergency appropriations, from a bond issuance or from amounts collected from SCE, PG&E and SDG&E. As a result of the situation in California, NRG’s interests in California are exposed to the heightened risk of delayed payments and/or non-payment regardless of whether the sales are made directly to PG&E, SCE or SDG&E or to the California ISO or the CDWR.

     NRG’s share of the net amounts owed to its California affiliates by the California PX, the California ISO and the three major California utilities totaled approximately $230 million as of Sept. 30, 2001. This amount reflects NRG’s share of (a) total amounts owed to its California affiliates of $371 million, less (b) amounts that are currently treated as disputed revenues and are not recorded as accounts receivable in the financial statements of NRG’s California affiliates, and reserves taken against accounts receivable that have been recorded in the financial statements, which together totaled $141 million. NRG believes that it will ultimately collect in full the net amount of $230 million owed to its California affiliates; however, if some form of financial relief or support is not provided to PG&E and SCE, the collectibility of this amount may become questionable in terms of both timing and amount. Disputed revenues related to billing that arise in the ordinary course of business must include justification for pricing higher than the California ISO and the FERC-imposed revenue caps on the wholesale price of electricity. None of these disputed revenues will be recorded until issues are resolved. Since the date of the PG&E bankruptcy filing, PG&E has been paying NRG’s Crockett and Mt. Poso affiliates on a current basis.

     The delayed collection of receivables owed to West Coast Power resulted in a covenant default under its credit agreement. West Coast Power has entered into a forbearance agreement with its lenders in connection with the covenant default. In addition, NRG’s Crockett affiliate was notified by its lenders that it has incurred a covenant default under its loan agreement. As a result, NRG has reclassified the long-term portion of the Crockett debt to current. Defaults under the Crockett and West Coast Power credit agreements do not trigger defaults under any of NRG’s corporate-level financing debt securities or borrowing arrangements.

     The FERC has jurisdiction over sales for resale of electricity in the California wholesale power markets. In March 2001, the FERC issued orders that presumptively approved prices up to $273 per megawatt-hour during January 2001 and $430 per megawatt-hour during February 2001. The orders direct electricity suppliers either to refund a portion of their January and February sales or justify prices charged above these approved prices. The orders, if finalized, could require West Coast Power to refund approximately $45 million in revenues from January and February, of which NRG’s share would be approximately $22.5 million. While Dynegy Power Marketing, Inc., as the power marketer for West Coast Power, has submitted information to justify each component of the prices it charged that were in excess of the presumptively approved prices, the FERC has rejected all of the generators’ submissions for excess prices for April 2001 through June 2001 (currently under appeal).

     On June 19, 2001, the FERC issued an order establishing a maximum pricing methodology for spot markets in California and throughout the Western Systems Coordinating Council (WSCC) region at times when reserves fall below 7 percent in California. The maximum price for sales in the WSCC spot markets during those hours, called the “market clearing price,” is derived from the costs of the least-efficient provider based in California and selling through the California ISO. At all other times, this order establishes a maximum price equal to 85 percent of the last market clearing price. This maximum price program will terminate on Sept. 30, 2002. The FERC also mandated settlement negotiations among sellers and buyers in the California ISO markets in respect to the settlement of past accounts, refund issues related to periods after Oct. 2, 2000, and the structuring of future arrangements for meeting California’s energy requirements. The settlement talks concluded without reaching a resolution on July 9, 2001. NRG cannot predict what action the FERC will take on any of the issues presented, including any refunds sought from the generators.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     French Island —NSP-Wisconsin’s French Island plant generates electricity by burning a mixture of wood waste and refuse-derived fuel. The fuel is derived from municipal solid waste furnished under a contract with LaCrosse County, Wisconsin. In 1997, the U.S. Environmental Protection Agency (EPA) found that the French Island plant was a “small municipal waste combustor” and therefore not subject to EPA regulations applicable to large combustors. In October 2000, the EPA reversed its decision and found that the plant was subject to the large combustor regulations. Those regulations became effective on Dec. 19, 2000. NSP-Wisconsin did not have adequate time to install the emission controls necessary to come into compliance with the large combustor regulations by the compliance date. As a result, on March 29, 2001, the EPA issued a finding of violation to the company. On April 2, 2001, a conservation group sent NSP-Wisconsin a notice of intent to sue under the citizen suit provisions of the Clean Air Act. On July 27, 2001, the state of Wisconsin filed a lawsuit against NSP-Wisconsin in the Wisconsin Circuit Court for LaCrosse County, contending that NSP-Wisconsin exceeded dioxin emission limits on numerous occasions between July 1995 and December 2000 at French Island. NSP-Wisconsin faces fines between $10,000 and $25,000 per day for each violation. NSP-Wisconsin is working with the EPA and other parties to minimize these fines and has recorded an estimate of its obligations under environmental regulations.

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

     In September 2001, NSP-Wisconsin received preliminary results of a stack test on French Island Unit 2, which indicated that the unit’s emissions during the stack test exceeded its dioxin limit. As a result, NSP-Wisconsin has stopped burning refuse-derived fuel in the boiler until it can complete the retrofit required for compliance with the federal large combustor requirements. NSP-Wisconsin expects that the retrofit will also allow it to comply with the state dioxin standard.

6.     Short-Term Borrowings and Financial Instruments

     At Sept. 30, 2001, Xcel Energy and its subsidiaries had approximately $2.2 billion of short-term debt outstanding at a weighted average interest rate of 3.38 percent.

     As of Sept. 30, 2001, Xcel Energy had several interest rate swaps with a notional amount of approximately $1.6 billion. The majority of these swaps were related to NRG. If the swaps were terminated at Sept. 30, 2001, Xcel Energy would have had to pay the counterparties approximately $87 million.

     NRG had several interest rate swap agreements outstanding at Sept. 30, 2001, with a total notional amount of approximately $1.6 billion. These swaps convert project financing from variable rate to fixed rate debt. If the swaps were terminated at Sept. 30, 2001, NRG would have had to pay the counterparties approximately $77 million. These swaps are described below.

•  One swap effectively converts approximately $20 million of non-recourse variable rate debt into fixed rate debt. The swap expires in September 2002 and is secured by the Camas Power Boiler assets.

•  One swap converts approximately $138 million of non-recourse variable rate debt into fixed rate debt. The swap expires in December 2014 and is secured by the Crockett Cogeneration assets.

•  One swap converts notional amount of GBP 188 million or approximately $277  million of non-recourse variable rate debt into fixed rate debt. The swap expires in June 2019 and is secured by the Killingholme assets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

•  One swap converts variable rate debt to fixed rate debt. The notional amount is the equivalent of approximately $52 million as of Sept. 30, 2001. The swap expires in September 2012 and is secured by the Flinders Power assets.

•  One swap converts $250 million of construction revolver variable rate debt into fixed rate debt. The swap expires in December 2002.

•  Several swaps convert variable rate debt to fixed rate debt. The notional amount is the equivalent of approximately $522 million as of Sept. 30, 2001. The swaps expire at various times between June 2002 and September 2006 and are secured by the LSP Kendell assets.

•  One swap converts USD floating rate into EUR fixed rate debt. The notional amount of this swap is approximately $78 million. The swap expires in February 2017 and is secured by the Csepel project assets.

•  Several swaps convert variable rate debt to fixed rate debt. The notional amount is the equivalent of approximately $224 million as of Sept. 30, 2001. The swaps expire at various times between July 2003 and July 2008 and are secured by the Brazos Valley assets.

     SPS has an interest rate swap with a notional amount of $25 million, converting variable rate debt to a fixed rate. Young Gas Storage and Quixx Linden projects, which are unconsolidated equity investments of Xcel Energy, have interest rate swaps converting project debt from variable rate to fixed rate. These two swaps had a total notional amount of approximately $40 million on Sept. 30, 2001. The approximate termination cost of Xcel Energy’s portion of these three swaps was approximately $10 million at Sept. 30, 2001.

7.     Segment Information

     Xcel Energy has the following reportable segments: Electric Utility, Gas Utility and two of its nonregulated energy businesses, NRG and e prime. During February 2001, Xcel Energy reached an agreement to sell the majority of its investment in Yorkshire Power. As a result of this sales agreement, Xcel International (Yorkshire Power was Xcel International’s most significant holding) is no longer a reportable segment. Prior periods have been restated for comparability. Trading operations are not a reportable segment; electric trading results are included in the Electric Utility segment and gas trading results are presented as e prime.

		Electric												Reconciling			Consolidated
		Utility		Gas Utility			NRG		e prime		All Other			Eliminations			Total
		(Thousands of dollars)
Three months ended Sept. 30, 2001
Operating revenues from external customers		$	2,133,608	$	216,030		$	852,548	$	373,027	$	76,428			—		$	3,651,641
Intersegment revenues			253		1,082			165		15,825		21,271			(37,784	)		812
Equity in earnings of unconsolidated affiliates			—		—			111,132		323		(434	)		—			111,021
	Total revenues	$	2,133,861	$	217,112		$	963,845	$	389,175	$	97,265		$	(37,784	)	$	3,763,474
Segment net income (loss)		$	183,442	$	(5,295	)	$	141,580	$	1,293	$	(40,103	)	$	(8,014	)	$	272,903

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

		Electric														Reconciling			Consolidated
		Utility			Gas Utility			NRG		e prime			All Other			Eliminations			Total
		(Thousands of dollars)
Three months ended Sept. 30, 2000
Operating revenues from external customers		$	1,916,720		$	175,907		$	532,554	$	317,794		$	51,919			—		$	2,994,894
Intersegment revenues			311			(3,171	)		301		23,052			(11,838	)		(6,477	)		2,178
Equity in earnings of unconsolidated affiliates			—			—			91,643		335			4,017			—			95,995
	Total revenues	$	1,917,031		$	172,736		$	624,498	$	341,181		$	44,098		$	(6,477	)	$	3,093,067
Segment income (loss) before extraordinary items		$	93,246		$	(16,513	)	$	88,604	$	(4,981	)	$	(49,353	)	$	(13,087	)	$	97,916
Extraordinary items, net of tax			(5,302	)		—			—		—			—			—			(5,302	)
Segment net income (loss)		$	87,944		$	(16,513	)	$	88,604	$	(4,981	)	$	(49,353	)	$	(13,087	)	$	92,614
Nine months ended Sept. 30, 2001
Operating revenues from external customers		$	6,084,738		$	1,576,732		$	2,134,724	$	1,449,139		$	249,838			—		$	11,495,171
Intersegment revenues			716			3,241			1,859		75,297			48,711			(128,681	)		1,143
Equity in earnings of unconsolidated affiliates			—			—			191,634		1,022			3,629			—			196,285
	Total revenues	$	6,085,454		$	1,579,973		$	2,328,217	$	1,525,458		$	302,178		$	(128,681	)	$	11,692,599
Segment net income (loss)		$	449,926		$	48,464		$	225,872	$	7,131		$	(62,637	)	$	(18,686	)	$	650,070
Nine months ended Sept. 30, 2000
Operating revenues from external customers		$	4,559,052		$	894,182		$	1,337,859	$	766,366		$	171,231			—		$	7,728,690
Intersegment revenues			880			4,801			902		32,229			22,698			(58,856	)		2,654
Equity in earnings of unconsolidated affiliates			—			—			130,171		852			35,492			—			166,515
	Total revenues	$	4,559,932		$	898,983		$	1,468,932	$	799,447		$	229,421		$	(58,856	)	$	7,897,859
Segment income (loss) before extraordinary items		$	272,899		$	24,451		$	140,931	$	(4,356	)	$	(13,075	)	$	(12,863	)	$	407,987
Extraordinary items, net of tax			(18,960	)		—			—		—			—			—			(18,960	)
Segment net income (loss)		$	253,939		$	24,451		$	140,931	$	(4,356	)	$	(13,075	)	$	(12,863	)	$	389,027

8.     Adoption of SFAS 133

     On Jan. 1, 2001, Xcel Energy adopted SFAS No. 133 — “Accounting for Derivative Instruments and Hedging Activity,” as amended by SFAS 137 and SFAS 138 (collectively referred to as SFAS 133). These statements require that all derivative instruments be recorded on the balance sheet at fair value. Changes in the derivative instrument’s fair value must be recognized currently in earnings unless specific accounting criteria are met or specific exclusions are applicable. Accounting for qualifying hedges within the terms of SFAS 133 allows a derivative instrument’s gains and losses to offset related results of the hedged item in the income statement, to the extent effective. SFAS 133 requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

     A fair value hedge requires that the effective portion of the change in the fair value of a derivative instrument be offset against the change in the fair value of the underlying asset, liability or firm commitment being hedged through earnings. A cash flow hedge requires that the effective portion of the change in the fair value of a derivative instrument be recognized in other comprehensive income, and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The ineffective portion of a

15

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

derivative instrument’s change in fair value is recognized in earnings. Additionally, both the fair value changes excluded from the effectiveness assessment and the time value component of options used as cash flow hedges are recognized in earnings.

     SFAS 133 applies to Xcel Energy’s energy and energy related commodities financial instruments, long-term power sales contracts and long-term gas purchase contracts used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investment in fuel inventories. SFAS 133 also applies to various interest rate swaps used to mitigate the risks associated with movements in interest rates and foreign exchange contracts to reduce the effect of fluctuating foreign currencies on foreign denominated investments and other transactions.

     Xcel Energy conducts energy acquisition, wholesale sales and trading activities through its utility and nonregulated operations. The primary objective of Xcel Energy’s energy acquisition and trading operations is to maximize asset value while simultaneously minimizing pricing and credit risks. These activities are subject to SFAS 133 as they typically meet the definition of derivative instruments. For the company’s regulated utility customers, Xcel Energy acquires electric capacity and energy as well as natural gas supplies. Included in this operation are certain wholesale trading activities to optimize asset utilization. Xcel Energy is exposed to some level of market and credit risk under its obligation to manage its retail electric distribution and natural gas needs. Xcel Energy enters into derivative instruments to hedge fuel requirements, inventories, excess generation capacity, and purchase power contracts. The nonregulated activities are conducted primarily by NRG and e prime, two nonregulated subsidiaries of Xcel Energy. As with the utility operations, derivative instruments are entered into which seek to optimize asset utilization, market inventories, minimize price and credit risks, and market and hedge existing supplies and purchases.

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

     The adoption of SFAS 133 on Jan. 1, 2001, resulted in an earnings impact of less than $1 million, which is not being reported separately as a cumulative effect of accounting change due to immateriality. In addition, upon adoption of SFAS 133, Xcel Energy recorded a net transition loss of approximately $29 million recorded in other comprehensive income. The impact to other comprehensive income is related to existing cash flow hedges during increasing price conditions.

     The components of SFAS 133 impacts on Xcel Energy’s other comprehensive income are detailed in the following table (in millions of dollars).

Net transition loss, Jan. 1, 2001	$	(28.8	)
After-tax net unrealized gains related to derivatives accounted for as hedges		7.3
After-tax net realized losses on derivative transactions reclassified into earnings		32.2
Other comprehensive income, Sept. 30, 2001	$	10.7

16

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The components of SFAS 133 impacts on Xcel Energy’s income statement are detailed in the following table (in millions of dollars except per share data).

		Three months ended			Nine months ended
		Sept. 30, 2001			Sept. 30, 2001
Nonregulated and other revenues		$	(10.2	)	$	(21.6	)
Equity earnings from investment in affiliates			(1.7	)		(0.9	)
Electric fuel and purchased power — utility			(1.2	)		(1.0	)
Cost of goods sold — nonregulated and other			(7.6	)		(12.8	)
Other income (deductions)			(2.2	)		0.0
	Gross impact before minority interest and income tax	$	(22.9	)	$	(36.3	)
Total impact to Xcel Energy’s net income		$	(11.5	)	$	(13.9	)
EPS impact (diluted)		$	(0.03	)	$	(0.04	)

     Energy and energy related commodities —Xcel Energy is exposed to commodity price variability and credit risk in its generation, retail distribution and energy trading operations. To manage these commodity price risks, Xcel Energy enters into financial instruments, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps. Derivatives designated to be hedges by Xcel Energy are accounted for as cash flow hedges and recorded as electric fuel and purchased power for Xcel Energy’s regulated subsidiaries, as cost of goods sold — nonregulated and other for Xcel Energy’s nonregulated subsidiaries, and as equity earnings from investment in affiliates for activities by NRG’s equity investments.

     Xcel Energy generally attempts to balance its fixed-price physical and financial purchase and sales commitments in terms of contract volumes, and the timing of performance and delivery obligations. These derivatives do not qualify for hedge accounting and, accordingly, changes in the fair value are reported in earnings. Furthermore, Xcel Energy has elected not to designate certain commodity derivatives considered to be economic hedges as accounting hedges due to the documentation requirements under SFAS 133.

     At Sept. 30, 2001, Xcel Energy had various commodity related contracts extending through December 2003 and several fixed-price gas purchase contracts extending through 2005 to 2018. During the next twelve months, Xcel Energy expects to reclassify into earnings net gains from other comprehensive income of approximately $9.6 million.

     Interest rates —To manage interest rate risk, Xcel Energy (primarily at NRG) has entered into interest rate swaps that effectively fix the interest payments of certain floating rate debt instruments. Interest rate swap agreements are accounted for as cash flow hedges and recorded as interest expense. Xcel Energy expects to reclassify into earnings during the next twelve months net losses from other comprehensive income of approximately $2.2 million.

     Foreign currency exchange rates —To preserve the U.S. dollar value of projected foreign currency cash flows, NRG may hedge, or protect, those cash flows if appropriate foreign hedging instruments are available. For the three and nine months ended Sept. 30, 2001, NRG had various foreign currency exchange contracts not designated as accounting hedges but as natural hedges. Accordingly, the changes in fair value of these derivatives are reported in other income (deductions) in the income statement.

17

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Cash flow hedge quantitative disclosures —The net gain (loss) recognized in earnings for derivative instruments that have been designated and qualify as cash flow hedging instruments are detailed in the following table (in millions of dollars).

					Derivatives			Firm commitments
					excluded from			no longer
		Hedge			assessment of			qualifying as cash
		ineffectiveness			hedge effectiveness			flow hedges
Three months ended Sept. 30, 2001:
	Energy and energy related commodities	$	(15.9	)	$	(1.2	)	$	(0.05	)
	Interest rates		—			—			—
Nine months ended Sept. 30, 2001:
	Energy and energy related commodities	$	(2.0	)	$	—		$	(0.04	)
	Interest rates		—			—			—

18

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Xcel Energy Inc.:

     We have reviewed the accompanying consolidated balance sheet of Xcel Energy Inc. (a Minnesota corporation) and subsidiaries as of September 30, 2001, the related consolidated statements of income and stockholders’ equity for the three-month and nine-month periods ended September 30, 2001 and 2000 and the related consolidated statement of cash flows for the nine-month period ended September 30, 2001 and 2000. These financial statements are the responsibility of the Company’s management. We did not review the interim financial statements of NRG Energy, Inc., whose total assets as of September 30, 2001, constitute 45 percent and total revenues for the three-month and nine-month periods ended September 30, 2001, constitute 26 percent and 20 percent, respectively, of the related consolidated totals, but were furnished with the report of other accountants of their review of those statements.

     We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

     Based on our review and report of other accountants, we are not aware of any material modifications that should be made to the consolidated financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States.

     We have previously audited, in accordance with auditing standards generally accepted in the United States, the balance sheet of Xcel Energy Inc. and subsidiaries as of December 31, 2000 (not presented herein), and, in our report dated March 2, 2001, we expressed an unqualified opinion on that statement. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2000 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

ARTHUR ANDERSEN LLP

Minneapolis, Minnesota

November 13, 2001

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Item 2.     Management’s Discussion and Analysis

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

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

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

•  business conditions in the energy industry;

•  competitive factors, including the extent and timing of the entry of additional competition in the markets served by Xcel Energy and its subsidiaries;

•  unusual weather;

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

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

•  currency translation and transaction adjustments;

•  risks associated with the California power market; and

•  the other risk factors listed from time to time by Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to this report on Form 10-Q for the quarter ended Sept. 30, 2001.

Results of Operations

     Earnings per Share Summary

     Xcel Energy’s earnings per share were $0.79 for the third quarter of 2001, compared with $0.27 for the third quarter of 2000. Xcel Energy’s earnings per share for the third quarter of 2000 were reduced by 43 cents for special charges related to the merger to form Xcel Energy and 2 cents per share for an extraordinary item related to the restructuring of SPS’ generation business.

     Xcel Energy’s earnings per share were $1.88 for the first nine months of 2001, compared with $1.14 for the first nine months of 2000. Xcel Energy’s earnings per share for the first nine months of 2000 were reduced by 43 cents for special charges related to the merger to form Xcel Energy and 6 cents per share for an

20

extraordinary item related to the restructuring of SPS’ generation business. The following table details the earnings per share contribution of Xcel Energy’s regulated and nonregulated businesses.

		Three months ended					Nine months ended
Earnings per share (EPS)		9/30/01		9/30/00			9/30/01		9/30/00
Regulated EPS before extraordinary item		$	0.53	$	0.20		$	1.52	$	0.95
Extraordinary item			0.00		(0.02	)		0.00		(0.06	)
Total regulated EPS			0.53		0.18			1.52		0.89
Nonregulated EPS			0.26		0.09			0.36		0.25
	Total Xcel Energy EPS	$	0.79	$	0.27		$	1.88	$	1.14

     Conservation Incentive Recovery —Regulated earnings for the first nine months of 2001 were increased by 7 cents per share due to the reversal of the Minnesota Public Utilities Commission (MPUC) decision to deny NSP-Minnesota recovery of 1998 conservation incentives.

     In June 1999, the MPUC denied NSP-Minnesota recovery of 1998 lost margins, load management discounts and incentives associated with state-mandated programs for electric energy conservation. Xcel Energy recorded a $35 million charge in 1999, which reduced earnings by 7 cents per share, based on this action. NSP-Minnesota appealed the MPUC decision and in December 2000, the Minnesota Court of Appeals reversed the MPUC decision.

     In January 2001, the MPUC appealed the lower court decision to the Minnesota Supreme Court. On Feb. 23, 2001, the Minnesota Supreme Court declined to hear the MPUC’s appeal. During the second quarter of 2001, NSP-Minnesota filed with the MPUC a plan that carried out, among other things, the court’s decision. On June 28, 2001, the MPUC approved the plan and issued an order to that effect shortly thereafter. As a result, the previously recorded liabilities of approximately $41 million (including carrying charges) for potential refunds to customers were no longer required and were reversed during the second quarter of 2001.

     This accounting adjustment increased second quarter revenue by approximately $35 million and increased allowance for funds used during construction (equity and debt) by approximately $6 million, increasing earnings by 7 cents per share. The revenue increase relates to the elimination of potential refunds of amounts previously billed and collected, and the other income represents reversal of accrued carrying charges.

     Postemployment Benefits —Earnings for the first nine months of 2001 were decreased by 4 cents per share due to a Colorado Supreme Court decision that resulted in a pretax write-off of $23 million of deferred postemployment benefit costs at PSCo. For more information, see Note 2 to the Financial Statements.

     Extraordinary Item Electric — Utility Restructuring —During the second quarter of 2000, SPS wrote off its generation-related regulatory assets and other deferred costs totaling approximately $19.3 million. This resulted in an after-tax extraordinary charge of approximately $13.7 million. During the third quarter of 2000, SPS recorded a charge of $8.2 million before tax, or $5.3 million after tax, related to the defeasance of first mortgage bonds. These extraordinary charges reduced Xcel Energy’s earnings by 4 cents per share for the second quarter of 2000 and 2 cents per share for the third quarter of 2000. For more information on restructuring, including the reapplication of regulatory accounting under SFAS 71 in 2001, see Note 4 to the Financial Statements.

     SFAS 133 —The adoption of SFAS 133 on Jan. 1, 2001, resulted in an earnings impact of less than $1 million, which is not being reported separately as a cumulative effect of accounting change due to immateriality. In addition, upon adoption of SFAS 133 Xcel Energy recorded a net transition loss of approximately $29 million recorded in other comprehensive income. At Sept. 30, 2001, Xcel Energy had cumulative gains recorded in other comprehensive income of $10.7 million. Other comprehensive income has also been affected each quarter since the implementation of SFAS of 133, as shown in the Statements of Consolidated Common Stockholders’ Equity. For more information on SFAS 133, see Note 8 to the Financial Statements.

21

     Xcel Energy’s earnings for the third quarter of 2001 were decreased by approximately $11.5 million (net of minority interest and after tax), or 3 cents per share, primarily at NRG, due to the mark-to-market impacts of SFAS 133 on the valuation of derivative instruments.

     Xcel Energy’s earnings for the first nine months of 2001 were decreased by approximately $13.9 million (net of minority interest and after tax), or 4 cents per share, primarily at NRG, due to the mark-to-market impacts of SFAS 133 on the valuation of derivative instruments.

Nonregulated Results

     The following table summarizes the earnings contributions of Xcel Energy’s nonregulated businesses:

		Three months ended						Nine months ended
Earning per share (EPS)		9/30/01			9/30/00			9/30/01			9/30/00
NRG Energy Inc.		$	0.31		$	0.23		$	0.50		$	0.35
Yorkshire Power			0.00			0.02			0.01			0.12
Seren Innovations Inc.			(0.02	)		(0.02	)		(0.06	)		(0.05	)
e prime			0.00			(0.02	)		0.02			(0.02	)
Planergy International			0.00			(0.05	)		(0.02	)		(0.06	)
Financing costs and preferred dividends			(0.03	)		(0.02	)		(0.09	)		(0.06	)
Other			0.00			(0.05	)		0.00			(0.03	)
	Total nonregulated EPS	$	0.26		$	0.09		$	0.36		$	0.25

     NRG —NRG’s earnings for the third quarter and first nine months of 2001 increased due to increased returns from a larger generation portfolio, contracted electricity sales, returns on power marketing activities and strong operating performance.

     Since September 2000, NRG has completed the acquisition of numerous operating projects that have contributed to the growth in NRG’s earnings from majority-owned operations. These acquisitions include: the Flinders Power facilities, Entrade AG (an energy trading company active in Europe), the LS Power assets, the Conectiv assets, the Csepel acquisition, the Hsin Yu acquisition, the Indeck acquisition, the McClain acquisition and the increased ownership and resulting consolidation of Schkopau. Each of these completed acquisitions and others of less significance have contributed substantially to the growth of NRG’s earnings from majority-owned operations for the three and nine months ended Sept. 30, 2001 as compared to the same periods in 2000.

     The NRG earnings for the third quarter and the first nine months of 2001 in this report exclude earnings of approximately 11 cents per share and 16 cents per share, respectively, related to minority shareholder interests. In comparison, NRG earnings for the third quarter and the first nine months of 2000 in this report exclude earnings of approximately 5 cents per share and 6 cents per share, respectively, related to minority shareholder interests.

     Yorkshire Power —During February 2001, Xcel Energy reached an agreement to sell the majority of its investment in Yorkshire Power to Innogy Holdings plc. As a result of this sales agreement, Xcel Energy did not record any equity earnings from Yorkshire Power after January 2001. For more information, see Note 3 to the Financial Statements.

     Seren —As expected, Seren’s construction of its broadband communications network in Minnesota and California resulted in higher losses for the first nine months of 2001. Seren is constructing a combination cable television, telephone and high-speed Internet access system in two locations, St. Cloud, Minn., and Contra Costa county in the east bay area of northern California. As of Sept. 30, 2001, Xcel Energy’s investment in Seren was approximately $235 million. Seren had capitalized $156 million for plant in service and had incurred another $60 million for construction work in progress for these systems at Sept. 30, 2001. The majority of the system construction in St. Cloud is expected to be completed this year. The ultimate viability of Seren is dependent on securing a customer and revenue base sufficient to recover the capital investment and ongoing operating costs. Management is currently evaluating the strategic fit of Seren’s telecommunication ventures in Xcel Energy’s business portfolio and may make a decision later in 2001 or early 2002.

22

     e prime —e prime’s results for the first nine months of 2001 reflect capitalizing on favorable market opportunities utilizing gas transportation and storage positions. These favorable market conditions may not continue to exist during the remainder of 2001 in the natural gas markets.

     e prime’s results for the third quarter of 2000 and the first nine months of 2000 were reduced by special charges of 2 cents per share for contractual obligations and other costs associated with post-merger changes.

     Planergy International —Planergy’s results for the third quarter of 2000 and the first nine months of 2000 were reduced by special charges of 4 cents per share for the write-offs of goodwill and project development costs at Planergy. During the third quarter of 2000, the operations of Planergy and Energy Masters International (EMI), both wholly owned subsidiaries of Xcel Energy, were combined and now do business as Planergy International. As a result of this merger, Planergy International reassessed its business model and made a strategic realignment, which resulted in the write-off of $22 million (before tax) of goodwill and project development costs.

     Financing Costs and Preferred Dividends —Nonregulated 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.

     Other —The Other Nonregulated results for the third quarter 2000 and the first nine months 2000 were reduced by special charges of 2 cents per share. These special charges include $10 million (before tax) in asset write-downs and losses resulting from various other nonregulated business ventures that are not being pursued after the merger.

     At Sept. 30, 2001, Xcel Energy had invested approximately $85 million in various international energy projects through its subsidiaries IPI and Xcel Argentina. Management is currently evaluating the strategic fit of these international energy ventures in Xcel Energy’s business portfolio and may make a decision later in 2001 or early 2002.

     Income Statement Analysis — Third Quarter 2001 vs. Third Quarter 2000

Electric Utility Margins

     The following table details the changes in electric utility revenue and margin. Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel clause cost recovery mechanisms for retail customers in several states, most fluctuations in energy costs do not materially affect electric margin. However, the fuel cost recovery mechanisms in the various jurisdictions do not allow for complete recovery of all variable production expenses, and, therefore, higher costs can result in an adverse margin and earnings impact. Electric margins reflect the impact of sharing energy costs and savings relative to a target cost per delivered kilowatt-hour and certain trading margins under the incentive cost adjustment (ICA) in Colorado.

		Three months ended
		9/30/01		9/30/00
		(Millions of
		dollars)
Electric retail and firm wholesale revenue		$	1,622	$	1,452
Short-term wholesale revenue			197		215
	Total electric utility revenue		1,819		1,667
Electric retail and firm wholesale fuel and purchased power			767		607
Short-term wholesale fuel and purchased power			173		184
	Total electric utility fuel and purchased power		940		791
Electric retail and firm wholesale margin			855		845
Short-term wholesale margin			24		31
	Total electric utility margin	$	879	$	876

23

     Electric revenue increased by approximately $152 million, or 9.1 percent, in the third quarter of 2001. Electric margin increased by approximately $3 million, or 0.3 percent, in the third quarter of 2001. Retail revenue and margin increased due to sales growth and more favorable temperatures. Favorable temperatures during the third quarter of 2001 increased retail revenue by approximately $15 million and retail margin by approximately $8 million, compared with the third quarter of 2000. There increases in margin were partially offset by increased fuel and purchased power costs, which are not completely recoverable from customers in Colorado due to various cost sharing mechanisms. Retail revenue and margin were also reduced in the third quarter of 2001 by approximately $3 million, due to rate reductions in various jurisdictions agreed to as part of the merger approval process. Short-term wholesale revenue and margin decreased due to lower market prices for electricity, reflecting a general decline in energy prices.

Gas Utility Margins

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

	Three months ended
	9/30/01			9/30/00
	(Millions of
	dollars)
Gas revenue	$	217		$	177
Cost of gas purchased and transported		(136	)		(84	)
Gas margin	$	81		$	93

     Gas revenue increased by approximately $40 million, or 22.6 percent, in the third quarter of 2001, primarily due to increases in the cost of natural gas, which are largely passed on to customers and recovered through various rate adjustment clauses in most of the jurisdictions in which Xcel Energy operates. Gas margin decreased by approximately $12 million, or 12.9 percent, in the third quarter of 2001, largely due to a revision to estimated purchased gas recovery accruals in Minnesota.

Electric and Gas Trading Margins

     Xcel Energy’s trading operations are conducted mainly by PSCo and e prime. Trading revenues and costs of goods sold do not include the revenue and production costs associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load or NRG. Margins from utility generating assets for utility operations are included in the short-term wholesale portion of Electric Utility Margins, discussed previously. Revenues and costs associated with energy produced from NRG’s generating assets and capacity to serve NRG are included in NRG’s results, which are presented in nonregulated margins. The trading margins reflect the impact of the sharing of certain trading margins under the ICA. The following table details the changes in electric and gas trading revenue and margin.

	Three months ended
	9/30/01			9/30/00
	(Millions of
	dollars)
Trading revenue	$	688		$	568
Trading cost of goods sold		(679	)		(555	)
Trading margin	$	9		$	13

     Trading revenue increased by approximately $120 million, while trading margin decreased by approximately $4 million for the third quarter of 2001. Trading margin decreased due to lower market prices for electricity, reflecting a general decline in energy prices.

24

Nonregulated Operating Margins

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

	Three months ended
	9/30/01			9/30/00
	(Millions of
	dollars)
Nonregulated and other revenue	$	929		$	585
Earnings from equity investments		111			96
Nonregulated cost of goods sold		(450	)		(270	)
Nonregulated margin	$	590		$	411

     Nonregulated revenue and margin increased for the third quarter of 2001, largely due to NRG, which had increased returns from a larger generation portfolio, contracted electricity sales, returns on power marketing activities and strong operating performance.

     Earnings from equity investments increased for the third quarter of 2001, due to increased equity earnings from NRG projects, which offset lower equity earnings from Yorkshire. As a result of a sales agreement to sell the majority of its investment in Yorkshire Power, Xcel Energy did not record any equity earnings from Yorkshire Power after January 2001.

Non-Fuel Operating Expense and Other Costs

     Regulated Other Operation and Maintenance Expenses for the third quarter of 2001 increased by approximately $39 million, or 11.9 percent, compared with the third quarter of 2000. The change is largely due to increased bad debt reserves resulting from higher energy prices, increased transmission costs from the Southwest Power Pool (which are offset in electric revenue), increased costs due to customer growth and increased nuclear costs to establish the Nuclear Management Co. and to maintain operational excellence at the nuclear plants.

     Nonregulated Other Operation and Maintenance Expenses increased by approximately $59 million, or 35.1 percent for the third quarter of 2001, compared with the third quarter of 2000, primarily due to the expansion of NRG’s operations including acquisition costs, business development activities and legal, technical and accounting expenses.

     Depreciation and amortization increased by approximately $50 million, or 24.6 percent, for the third quarter of 2001, compared with the third quarter of 2000, primarily due to acquisitions of generating facilities by NRG and increased capital additions to utility plant.

     Taxes (other than income taxes) declined largely due to a legislative change in Minnesota that reduced annual property taxes by approximately $30 million. Approximately 70 percent of this reduction in property taxes will be returned to NSP-Minnesota customers. In addition, property taxes were lower in Colorado.

     Interest expense increased by approximately $36 million, or 20.6 percent, for the third quarter of 2001, compared with the third quarter of 2000, primarily due to increased debt levels to fund several asset acquisitions by NRG.

     Other income-net increased by approximately $28 million for the third quarter of 2001, primarily due to higher interest income on temporary cash investments, largely at NRG.

     The effective tax rate used for recording income taxes for the third quarter of 2000 is higher than 2001 due to the effects of merger-related costs expensed in the third quarter of 2000, which were not tax deductible.

25

     Income Statement Analysis — First Nine Months of 2001 vs. First Nine Months of 2000

Electric Utility Margins

     The following table details the changes in electric utility revenue and margin. Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel clause cost recovery mechanisms for retail customers in several states, most fluctuations in energy costs do not materially affect electric margin. However, the fuel cost recovery mechanisms in the various jurisdictions do not allow for complete recovery of all variable production expenses, and, therefore, higher costs can result in an adverse margin and earnings impact. Electric margins reflect the impact of sharing energy costs and savings relative to a target cost per delivered kilowatt-hour and certain trading margins under the ICA in Colorado.

		Nine months ended
		9/30/01		9/30/00
		(Millions of
		dollars)
Electric retail and firm wholesale revenue		$	4,335	$	3,792
Short-term wholesale revenue			675		371
	Total electric utility revenue		5,010		4,163
Electric retail and firm wholesale fuel and purchased power			2,018		1,504
Short-term wholesale fuel and purchased power			529		300
	Total electric utility fuel and purchased power		2,547		1,804
Electric retail and firm wholesale margin			2,317		2,288
Short-term wholesale margin			146		71
	Total electric utility margin	$	2,463	$	2,359

     Electric revenue increased by approximately $847 million, or 20.3 percent, for the first nine months of 2001. Electric margin increased by approximately $104 million, or 4.4 percent, for the first nine months of 2001. Electric retail revenue increased largely due to increases in fuel costs and purchased power expenses. Retail electric revenue and margin also increased due to sales growth, more favorable weather conditions in the first nine months of 2001 and the recovery of conservation incentives in Minnesota. As discussed previously, the reversal of the MPUC decision to deny NSP-Minnesota recovery of 1998 conservation incentives increased retail revenue and margin by $35 million. Favorable temperatures during the first nine months of 2001 increased retail revenue by approximately $65 million and retail margin by approximately $41 million. These increases were partially offset by increased fuel and purchased power costs, which are not completely recoverable from customers in Colorado due to various cost sharing mechanisms. Retail revenue and margin were also reduced in the first nine months of 2001 by approximately $16 million due to rate reductions in various jurisdictions agreed to as part of the merger approval process.

     Short-term wholesale revenue and margin increased due to the expansion of Xcel Energy’s wholesale marketing operations and favorable market conditions, including strong prices in the western markets for the first half of 2001. It is not expected that short-term wholesale margins during the remainder of 2001 and 2002 will be as strong, due to declines in the forward price curve in the energy market.

Gas Utility Margins

     The following table details the changes in gas utility revenue and margin. The cost of gas tends to vary with changing sales requirements and the unit cost of gas purchases. However, due to purchased gas cost

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recovery mechanisms for retail customers, fluctuations in the cost of gas have little effect on natural gas margin.

	Nine months ended
	9/30/01			9/30/00
	(Millions of dollars)
Gas revenue	$	1,577		$	896
Cost of gas purchased and transported		(1,200	)		(543	)
Gas margin	$	377		$	353

     Gas revenue increased by approximately $681 million, or 76.0 percent, for the first nine months of 2001, primarily due to increases in the cost of natural gas, which are largely passed on to customers and recovered through various rate adjustment clauses in most of the jurisdictions in which Xcel Energy operates. Gas margin increased by approximately $24 million, or 6.8 percent, for the first nine months of 2001. Gas revenue and margin also increased due to customer growth and more favorable temperatures. More favorable temperatures during the first nine months of 2001 increased gas revenue by approximately $61 million and gas margin by approximately $21 million. Gas margin was also increased due to higher rates from a 2000 rate case in Colorado, effective Feb. 1, 2001. These gas revenue and margin increases were partially offset by a revision to estimated purchased gas recovery accruals in Minnesota and customer conservation efforts in reaction to higher natural gas prices.

Electric and Gas Trading Margins

     Xcel Energy’s trading operations are conducted mainly by PSCo and e prime. Trading revenues and costs of goods sold do not include the revenue and production costs associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load or NRG. Margins from utility generating assets for utility operations are included in the short-term wholesale portion of Electric Utility Margins, discussed previously. Trading revenues and costs associated with energy produced from NRG’s generating assets and capacity to serve NRG are included in NRG’s results, which are presented in nonregulated margins. Trading margins reflect the impact of sharing certain trading margins under the ICA. The following table details the changes in electric and gas trading revenue and margin.

	Nine months ended
	9/30/01			9/30/00
	(Millions of dollars)
Trading revenue	$	2,524		$	1,163
Trading cost of goods sold		(2,433	)		(1,133	)
Trading margin	$	91		$	30

     Trading revenue increased by approximately $1,361 million and trading margin increased by approximately $61 million for the first nine months of 2001. The increase in trading revenue and margin is a result of the expansion of electric trading at PSCo and natural gas trading at e prime and favorable market conditions, including strong prices in the western markets. It is not expected that trading margins during the remainder of 2001 and 2002 will be as strong, due to declines in the forward price curve in the energy market.

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Nonregulated Operating Margins

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

	Nine months ended
	9/30/01			9/30/00
	(Millions of dollars)
Nonregulated and other revenue	$	2,385		$	1,509
Earnings from equity investments		196			167
Nonregulated cost of goods sold		(1,274	)		(691	)
Nonregulated margin	$	1,307		$	985

     Nonregulated revenue and margin increased for the first nine months of 2001, largely due to NRG, which had increased returns from a larger generation portfolio, contracted electricity sales, returns on power marketing activities and strong operating performance.

     Earnings from equity investments for the first nine months of 2001 increased compared with the first nine months of 2000 due to increased equity earnings from NRG projects, which offset lower equity earnings from Yorkshire. As a result of a sales agreement to sell the majority of its investment in Yorkshire Power, Xcel Energy did not record any equity earnings from Yorkshire Power after January 2001.

Non-Fuel Operating Expense and Other Costs

     Regulated Other Operation and Maintenance Expenses increased by approximately $66 million, or 6.4 percent, for the first nine months of 2001, compared with the first nine months of 2000. The change is largely due to increased bad debt reserves resulting from higher energy prices, increased transmission costs from the Southwest Power Pool (which are offset in electric revenue), increased costs due to customer growth, plant outage timing and increased nuclear costs to establish the Nuclear Management Co. and to maintain operational excellence at the nuclear plants.

     Nonregulated Other Operation and Maintenance Expenses increased by approximately $161 million, or 36.1 percent, for the first nine months of 2001, compared with the first nine months of 2000, primarily due to expansion of NRG’s operations including acquisition costs, business development activities and legal, technical and accounting expenses.

     Depreciation and amortization increased by approximately $101 million, or 17.4 percent, for the first nine months of 2001, compared with the first nine months of 2000, primarily due to acquisitions of generating facilities by NRG and increased capital additions to utility plant.

     Taxes (other than income taxes) declined largely due to a legislative change in Minnesota that reduced annual property taxes by approximately $30 million. Approximately 70 percent of this reduction in property taxes will be returned to NSP-Minnesota customers. In addition, property taxes were lower in Colorado primarily due to the timing of a business and personal property tax refund from calendar year 2000.

     Interest expense increased by approximately $87 million, or 17.9 percent for the first nine months of 2001, compared with the first nine months of 2000, primarily due to increased debt levels to fund several asset acquisitions by NRG.

     Other income-net increased by approximately $46 million in the first nine months of 2001, compared with the first nine months of 2000, largely due to higher interest income on temporary cash investments, primarily at NRG. In addition in March 2001, Xcel Energy sold its Boulder Hydro facility in Colorado and recorded a gain of $11 million (before tax), which was shared with customers due to its inclusion in the PSCo Electric Earnings Test in Colorado.

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Pending Accounting Changes

     SFAS 142 —In June 2001, the Financial Accounting Standards Board (FASB) approved the issuance of SFAS No. 142 — “Goodwill and Other Intangible Assets.” This statement will require new accounting for intangible assets, including goodwill. Intangible assets will be amortized over their economic useful life and reviewed for impairment in accordance with SFAS No. 121 — “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” Goodwill will no longer be amortized. Instead, goodwill and intangible assets that will not be amortized should be tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below its carrying value. An impairment test is required to be performed within six months of the date of adoption, and the first annual impairment test must be performed in the year the statement is initially adopted.

     SFAS 142 is effective for Xcel Energy and its subsidiaries as of Jan. 1, 2002. At Sept. 30, 2001, Xcel Energy had unamortized intangible assets of $164 million, including $70 million of goodwill, mainly at its nonregulated subsidiaries. These amounts and all intangible assets and goodwill acquired in the future will be accounted for under the new accounting standard. The new accounting can be expected to initially increase earnings due to the elimination of regular amortization expense, but occasionally cause reductions in earnings when impairment write-downs of goodwill and/or intangible assets are required. Xcel Energy is in the process of evaluating the effects SFAS 142, but expects the earnings impact to be immaterial and does not expect to recognize any asset impairments.

     SFAS 143 —In June 2001, the FASB approved the issuance of SFAS No. 143 — “Accounting for Asset Retirement Obligations.” This statement will require Xcel Energy to record its future nuclear plant decommissioning obligations as a liability at fair value with a corresponding increase to the carrying value of the related long-lived asset. The liability will be increased to its present value each period, and the capitalized cost will be depreciated over the useful life of the related long-lived asset. If the recorded liability differs from the actual obligations paid, a gain or loss will be currently recognized.

     Xcel Energy currently follows industry practice by ratably accruing the costs for decommissioning over the approved cost recovery period and including the accruals in accumulated depreciation. At Dec. 31, 2000, Xcel Energy recorded and recovered in rates $583 million of decommissioning obligations and had total estimated discounted decommissioning cost obligations of $838 million.

     If Xcel Energy adopted the standard on Jan. 1, 2001, the initial value of the liability, including cumulative interest expense through that date, would have been approximately $705 million, with an offsetting increase to net plant assets of approximately $600 million. The resulting cumulative effect adjustment for unrecognized depreciation and other expenses under the new standard is approximately $105 million. Management expects that the entire transition amount would be recoverable in rates and, therefore, would recognize an additional regulatory asset rather than reporting a cumulative effect of accounting change in the income statement.

     SFAS 143 will also affect Xcel Energy’s accrued plant removal costs for other generation, transmission and distribution facilities for its utility subsidiaries. Xcel Energy expects that these costs, which have yet to be estimated, will be reclassified from accumulated depreciation to regulatory liabilities based on the recoverability of these costs in rates. Xcel Energy expects to adopt SFAS 143 on Jan. 1, 2003.

     SFAS 144 —In October 2001, the FASB issued SFAS No. 144 — “Accounting for the Impairment or Disposal of Long-Lived Assets,” that supercedes previous guidance for measurement of asset impairments under SFAS No. 121 and reporting for the disposal of a segment of a business under APB Opinion No.30.

     SFAS No. 144 retains the fundamental recognition and measurement provisions of SFAS No. 121, and also provides specific guidance for fair value measurement and disposal plan criteria. Additionally, SFAS No. 144 broadens the reporting criteria to allow discontinued operations treatment for any component of a entity with separately identifiable operations not just segments of a business, as under APB Opinion No. 30. Under SFAS No. 144, Xcel Energy will be required to measure discontinued operations at the lower of

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carrying value or fair value less cost to sellnotnet realizable value as was previously required, and discontinued operations will no longer include operating losses that have not yet occurred.

     SFAS No. 144 will be effective for Xcel Energy beginning Jan. 1, 2002 and will be applied on a prospective basis. Adoption of SFAS No. 144 is not expected to have a material impact on Xcel Energy.

Stockholder Protection Rights Agreement

     Xcel Energy has adopted a Stockholder Protection Rights Agreement. Under this agreement, rights were distributed as a dividend at the rate of one right per each share of Xcel Energy’s common stock. The dividend was paid to shareholders of record June 28, 2001. Under its principal provision, if any person or group acquires 15 percent or more of Xcel Energy’s outstanding common stock, all other shareholders of Xcel Energy would be entitled to buy, for the exercise price of $95 per right, common stock of Xcel Energy having a market value equal to twice the exercise price, thereby substantially diluting the acquiring person’s or group’s investment. The rights may cause substantial dilution to a person or group that acquires 15 percent or more of Xcel Energy’s common stock. The rights should not interfere with a transaction that is in the best interests of Xcel Energy and its shareholders because the rights can be redeemed prior to a triggering event for $0.01 per right.

Market Risks

     Xcel Energy and its subsidiaries are exposed to market risks, including changes in commodity prices, interest rates and currency exchange rates as disclosed in Management’s Discussion and Analysis in its annual report on Form 10-K for the year ended Dec. 31, 2000. Commodity price and interest rate risks for Xcel Energy’s regulated subsidiaries are mitigated in most jurisdictions due to cost-based rate regulation. There have been no material changes in the market risk exposures that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2000, with the exception of the risks associated with the California power market as discussed in Note 5 to Financial Statements.

Liquidity and Capital Resources

     Cash Flows

	Nine months
	ended Sept. 30
	2001		2000
Net cash provided by operating activities (in millions)	$	1,338	$	975

     Cash provided by operating activities increased for the first nine months of 2001, compared with the first nine months of 2000. The increase was mainly attributable to the increase in net income.

	Nine months ended
	Sept. 30
	2001			2000
Net cash used in investing activities (in millions)	$	(4,623	)	$	(2,807	)

     Cash used in investing activities increased for the first nine months of 2001, compared with the first nine months of 2000. The change is largely due to increased levels of nonregulated capital expenditures and asset acquisitions, primarily at NRG. The increase was partially offset by Xcel Energy’s sale of the majority of its investment in Yorkshire Power.

	Nine months ended
	Sept. 30
	2001		2000
Net cash provided by financing activities (in millions)	$	3,364	$	1,956

     Cash provided by financing activities increased for the first nine months of 2001, compared with the first nine months of 2000. The cash provided by financing activities for both periods reflects the issuance of debt and equity by NRG to fund various asset acquisitions. The change is largely due to increased short-term borrowings and lower repayments of long-term debt.

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     Financing Activities

     NRG Public Offering —In March 2001, NRG issued 18.4 million shares of common stock at a price of $27 per share and 11.5 million corporate units at a price of $25 per unit. The net proceeds from the offerings were approximately $753 million, including $478 million recorded in NRG’s common equity and $275 million recorded in long-term debt instruments of NRG. The offering’s net proceeds were received only by NRG and were used for NRG’s general corporate purposes, including funding a portion of NRG’s project investments and other capital requirements.

     Management has concluded that offerings of NRG stock in 2000 and 2001 do not affect Xcel Energy’s ability to use the pooling-of-interests method of accounting for the merger of NSP and NCE. The 2001 secondary offering caused Xcel Energy’s ownership interest in NRG to decline from approximately 82 percent to approximately 74 percent. A portion of the 2001 offering proceeds was accounted for as a gain on the sale of Xcel Energy’s ownership in NRG. This gain of $242 million was not recorded in earnings, but, consistent with Xcel Energy’s accounting policy, was recorded as an increase in the common stock premium component of stockholders’ equity.

     NRG Financings —In April 2001, NRG issued $350 million of 7.75 percent senior notes due April 2011 and $340 million of 30-year, 8.625 percent notes. The proceeds were used to repay short-term debt incurred to fund acquisitions and other general corporate purposes.

     In May 2001, NRG entered into a $2 billion revolving credit facility with various lenders. The facility will be used to finance the acquisition, development and construction of power generating plants located in the United States and to finance the acquisition of turbines for such facilities. The facility provides for borrowings of base rate loans and Eurocurrency loans and is secured by mortgages and security agreements in respect of the assets of the projects financed under the facility, pledges of the equity interests in the subsidiaries or affiliates of the borrower that own such projects, and by guaranties from each such subsidiary or affiliate. Provided that certain conditions are met, NRG may repay loans and have the liens relating to that project released. NRG is permitted under the facility to repay borrowed funds, thus making them available to be borrowed again. The facility terminates in May 2009. The facility is non-recourse to NRG other than the obligation to contribute equity at certain times in respect to projects and turbines financed under the facility.

     In June 2001, NRG entered into a $600 million term loan facility with various lenders. The facility is unsecured and provides for borrowings of base rate loans and Eurocurrency loans. The facility terminates on June 21, 2002.

     In June 2001, NRG filed a shelf registration with the SEC to sell up to $2 billion in debt securities, common and preferred stock, warrants and other securities. NRG expects to use the net proceeds for general corporate purposes, which may include the financing and development of new facilities, working capital and debt reduction. In July 2001, NRG issued $500 million of debt securities under this shelf registration. The first tranche was $340 million of 6.75 percent senior notes due July 2006 and the second tranche was $160 million of 8.625 percent notes due April 2031. The $160 million tranche was a reopening of the 30-year bonds issued by NRG in April 2001. NRG used the proceeds to pay down its revolving credit facility, to provide capital for planned acquisitions and other general corporate purposes.

     In June 2001, NRG Midatlantic Generating LLC, a wholly owned subsidiary of NRG, borrowed approximately $415 million under a five-year term loan agreement to finance, in part, the acquisition of certain generating facilities from Conectiv. The agreement terminates in November 2005 and provides for a total credit facility of $580 million.

     In June 2001, in connection with NRG’s acquisition of the Csepel facilities, NRG assumed a non-recourse credit facility agreement that provides for borrowings of approximately $78.5 million and DEM 203.6 million. As of Sept. 30, 2001, there was an outstanding balance of approximately $173.1 million under this credit facility. The facility terminates in 2017 with principal payments due quarterly in varying amounts throughout the term of the agreement.

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     As part of NRG’s acquisition of the LS Power assets in January 2001, NRG through its wholly owned subsidiary, LSP Kendall Energy LLC, acquired a $554.2 million credit facility. The facility is non-recourse to NRG and consists of a construction and term loan, working capital and letter of credit facilities. As of Sept. 30, 2001, there was an outstanding balance of approximately $468.6 million outstanding under the facility.

     In June 2001, NRG through its wholly owned subsidiaries, Brazos Valley Energy LP and Brazos Valley Technology LP, entered into a $180 million non-recourse construction credit facility to fund the construction of the 600-megawatt Brazos Valley gas-fired, combined cycle merchant generation facility located in Fort Bend County, Texas. As of Sept. 30, 2001, there was an outstanding balance of $115 million under this credit agreement.

     NSP-Minnesota Shelf Registration —In April 2001, NSP-Minnesota filed a $600 million long-term debt shelf registration with the SEC. NSP-Minnesota may issue debt under this shelf registration during the fourth quarter of 2001 or the first quarter of 2002.

     SPS Financing —In October 2001, SPS issued $500 million of long-term debt. The senior notes have a coupon of 5.125 percent and mature in November 2006. The proceeds were used to repay short-term debt.

     Short-term debt and financial instruments are discussed in Note 6 to the Financial Statements.

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PART II.     OTHER INFORMATION

Item 1.     Legal Proceedings

     In the normal course of business, various lawsuits and claims have arisen against Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. See Notes 4 and 5 of the Financial Statements in this Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 of Xcel Energy’s 2000 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.

     Light Rail Lawsuit —In February 2001, NSP-Minnesota filed a lawsuit in the U.S. District Court in Minneapolis seeking reimbursement of costs for relocating electric utility lines to allow for construction of a light rail line in downtown Minneapolis, which is scheduled to open in 2004. The Minnesota Department of Transportation and the Metropolitan Council have requested the Court order NSP-Minnesota to immediately begin the relocation or to post a damage bond of $330 million to cover the cost of potential delays to the project. On May 24, 2001, the Court issued a preliminary injunction ordering NSP-Minnesota to move certain facilities. The decision as to who must pay the cost of relocation will be made after a trial in the spring of 2002. NSP-Minnesota has appealed the injunction order to the Eighth Circuit Court of Appeals in St. Louis, Mo. The Court of Appeals agreed to expedite its consideration of the appeal and oral argument was held on Oct. 18, 2001. The Court of Appeals refused to lift the preliminary injunction; however, the Court required the Minnesota Department of Transportation and Metropolitan Council to post a $8 million bond in the event NSP-Minnesota is successful at trial. Pending the trial, utility line relocation has commenced and NSP-Minnesota is capitalizing its costs incurred as construction work in progress.

     U.S. Department of Energy (DOE) Lawsuit —On June 8, 1998, NSP-Minnesota filed a complaint in the Court of Federal Claims against the DOE, requesting damages in excess of $1 billion for the DOE’s partial breach of the Standard Contract. NSP-Minnesota requested damages consisting of the costs of storing of spent nuclear fuel at the Prairie Island nuclear generating plant, anticipated costs related to the Private Fuel Storage, LLC and costs related to the 1994 state legislation limiting the number of casks that can be used to store spent nuclear fuel at Prairie Island. On April 6, 1999, the Court of Federal Claims dismissed NSP-Minnesota’s complaint. On May 20, 1999, NSP-Minnesota appealed to the Court of Appeals for the Federal Circuit. On Aug. 31, 2000, the Court of Appeals for the Federal Circuit reversed and remanded to the Court of Federal Claims. On Dec. 26, 2000, NSP-Minnesota filed a motion with the Court of Federal Claims to amend its complaint and renew its motion for summary judgment on the DOE’s liability. These motions are pending before the Court of Federal Claims. On Jan. 9, 2001, the DOE filed a motion with the Chief Judge for the Court of Federal Claims asking that all cases against the DOE arising out of alleged breaches of the Standard Contract be reassigned to one judge. The DOE also asked for the extraordinary remedy of binding parties not currently party to an action before the Court of Claims to a determination in the proposed consolidated action. Over the course of the summer of 2001, Judge Wiese held a number of conferences with counsel for the DOE and the utilities. Judge Wiese has thus far refused to consolidate actions and has stated that the actions should continue before different judges. He has consolidated aspects of discovery. Judge Wiese has also thus far refused to bind parties not currently party to an action before the Court of Claims. DOE has issued a number of subpoenas to parties not currently party to an action. Discovery is proceeding. A trial in NSP-Minnesota’s suit against the DOE is not likely to occur before the fourth quarter of 2002.

     Stray Voltage Case —On Sept. 25, 2000, NSP-Wisconsin was served with a complaint in Eau Claire County Circuit Court, alleging that stray voltage from NSP-Wisconsin’s system harmed the plaintiff’s dairy herd, resulting in lost milk production, lost profits and income, property damage, and injury to the dairy herd. The complaint also alleges that NSP-Wisconsin acted willfully and wantonly, entitling plaintiffs to treble damages. The plaintiffs allege farm damages of approximately $3.8 million. A 10-day trial, commencing Dec. 2, 2002, has been scheduled. NSP-Wisconsin plans to vigorously defend this complaint. The financial

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impact, if any, of this case is not determinable at this time. Insurance coverage may mitigate the impact of an adverse outcome, should it occur.

     Craig Station —In 1996, a conservation organization filed a complaint in the U. S. District Court pursuant to provisions of the Clean Air Act against the joint owners of the Craig Steam Electric Generating Station, located in western Colorado. Tri-State Generation and Transmission Association, Inc. is the operator of the Craig station and PSCo owns an undivided interest in each of two units at the station, totaling approximately 9.7 percent. In October 2000, the parties, the EPA and the Colorado Department of Public Health and Environment (CDPHE) reached an agreement in principle resolving all air quality matters related to the facility. The final agreement was negotiated during the fourth quarter of 2000 and was filed with the court on Jan. 10, 2001. The final agreement requires the installation of additional emission control equipment at a cost of approximately $105 million (based on an estimate from Tri-State). The equipment will be installed over a period of several years. In addition, the settlement requires the defendants collectively to pay a civil penalty of $500,000 and to contribute $1.5 million to fund conservation activities. The contribution to conservation activities will be refunded if the plant achieves a specified level of emissions control. The agreement became enforceable after approval by the court on March 19, 2001. The costs of installing the new equipment at the Craig Station is included in PSCo’s construction expenditure projections.

Item 6.     Exhibits and Reports on Form 8-K

(a) Exhibits

     The following Exhibits are filed with this report:

15	Letter from Arthur Andersen LLP regarding unaudited interim information for Xcel Energy.
99.01	Statement pursuant to Private Securities Litigation Reform Act.

(b) Reports on Form 8-K

     The following reports on Form 8-K were filed either during the three months ended Sept. 30, 2001, or between Sept. 30, 2001, and the date of this report:

     June 28, 2001 (filed July 12, 2001) — Item 5. Other Events. Re: Disclosure regulatory adjustments related to the reversal of an MPUC decision to deny recovery of NSP-Minnesota’s conservation incentives and the Colorado Supreme Court decision denying PSCo recovery of deferred costs for employees’ postemployment benefits.

     Sept. 28, 2001 (filed Sept. 28, 2001) — Item 5 and 7. Other Events and Exhibits. Re: Disclosure of Xcel Energy and other utilities filing for approval to form an independent transmission company.

     Oct. 11, 2001 (filed Oct. 12, 2001) — Item 5 and 7. Other Events and Exhibits. Re: Disclosure of Xcel Energy’s expected range of third quarter earnings.

     Oct. 29, 2001 (filed Oct. 29, 2001) — Item 5. Other Events. Re: Disclosure of presentation of Xcel Energy to the financial community regarding annual financial conditions.

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