Public Service Co Of Colorado 10Q 2001 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


(Mark One)
þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the quarterly period ended September 30, 2001

or

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

		For the transition period from to


	Exact name of registrant as specified in its charter, State or other
Commission	jurisdiction of incorporation or organization, Address of principal	IRS Employer
File Number	executive offices and Registrant’s Telephone Number, including area code	Identification No.

000-31709	NORTHERN STATES POWER COMPANY (a Minnesota Corporation) 414 Nicollet Mall, Minneapolis, Minn. 55401 Telephone (612) 330-5500		41-1967505
001-3140	NORTHERN STATES POWER COMPANY (a Wisconsin Corporation) 1414 W. Hamilton Ave., Eau Claire, Wis. 54701 Telephone (715) 839-2621		39-0508315
001-3280	PUBLIC SERVICE COMPANY OF COLORADO (a Colorado Corporation) 1225 17^thStreet, Denver, Colo. 80202 Telephone (303) 571-7511		84-0296600
001-3789	SOUTHWESTERN PUBLIC SERVICE COMPANY (a New Mexico Corporation) Tyler at Sixth, Amarillo, Texas 79101 Telephone (303) 571-7511		75-0575400

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

Northern States Power Co. (a Minnesota corporation), Northern States Power Co. (a Wisconsin corporation), Public Service Co. of Colorado and Southwestern Public Service Co. meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to such Form 10-Q.

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. All outstanding common stock is owned beneficially and of record by Xcel Energy Inc., a Minnesota corporation. Shares outstanding at Oct. 31, 2001:


Northern States Power Co. (a Minnesota Corporation)	Common Stock, $0.01 par value	1,000,000 Shares
Northern States Power Co. (a Wisconsin Corporation)	Common Stock, $100 par value	933,000 Shares
Public Service Co. of Colorado	Common Stock, $0.01 par value	100 Shares
Southwestern Public Service Co.	Common Stock, $1 par value	100 Shares

TABLE OF CONTENTS


PART 1. FINANCIAL INFORMATION
	Item 1. Consolidated Financial Statements
	Item 2. Management’s Discussion and Analysis
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Item 6. Exhibits and Reports on Form 8-K
Letter from Arthur Andersen LLP
Letter from Arthur Andersen LLP
Letter from Arthur Andersen LLP
Stmt pursuant to Private Sec Litigation Reform Act

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION


Item 1. Financial Statements
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

PART II — OTHER INFORMATION


Item 1. Legal Proceedings
Item 6. Exhibits and Reports on Form 8-K

This combined Form 10-Q is separately filed by Northern States Power Co., a Minnesota corporation (NSP-Minnesota), Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin), Public Service Co. of Colorado (PSCo) and Southwestern Public Service Co. (SPS). NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are all wholly owned subsidiaries of Xcel Energy Inc. Xcel Energy is a registered holding company under the Public Utility Holding Company Act (PUHCA). Additional information on Xcel Energy is available on various filings with the SEC.

Information contained in this report relating to any individual company is filed by such company on its own behalf. Each registrant makes representations only as to itself and makes no other representations whatsoever as to information relating to the other registrants.

This report should be read in its entirety. No one section of the report deals with all aspects of the subject matter.

PART 1. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME



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

			2001			2000			2001			2000


			(Unaudited)
			(Thousands of Dollars)
Operating revenues:
	Electric utility		$	765,607		$	696,290		$	2,034,081		$	1,807,919
	Gas utility			51,691			64,741			497,361			300,011

		Total operating revenues		817,298			761,031			2,531,442			2,107,930
Operating expenses:
	Electric fuel and purchased power			322,127			251,469			806,986			637,307
	Cost of gas sold and transported			38,309			44,474			392,824			199,961
	Other operating and maintenance expenses			189,476			175,871			580,899			555,847
	Depreciation and amortization			82,536			80,743			249,130			241,992
	Taxes (other than income taxes)			27,800			54,691			129,141			158,840
	Special charges (see Note 2)			0			59,059			0			59,059

		Total operating expenses		660,248			666,307			2,158,980			1,853,006

Operating income				157,050			94,724			372,462			254,924
Other income (deductions) — net				(2,609	)		(870	)		(2,270	)		(763	)
Interest charges and financing costs:
	Interest charges — net of amounts capitalized			21,199			32,681			65,537			93,487
	Distributions on redeemable preferred securities of subsidiary trust			3,938			3,938			11,813			11,813

		Total interest charges and financing costs		25,137			36,619			77,350			105,300

Income before income taxes				129,304			57,235			292,842			148,861
Income taxes				53,214			32,072			118,179			66,590

Net income			$	76,090		$	25,163		$	174,663		$	82,271

The Notes to Consolidated Financial Statements are an integral part of the Financial Statements.

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS



				Nine Months Ended
				Sept. 30

				2001			2000


				(Unaudited)
				(Thousands of Dollars)
Operating activities:
	Net income			$	174,663		$	82,271
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			259,607			254,214
		Nuclear fuel amortization			31,843			32,937
		Deferred income taxes			7,532			(3,477	)
		Amortization of investment tax credits			(6,108	)		(6,149	)
		Allowance for equity funds used during construction			(4,676	)		1,025
		Conservation incentive adjustments			(32,218	)		19,966
		Change in accounts receivable			71,010			15,419
		Change in inventories			(3,803	)		(16,994	)
		Change in other current assets			63,376			52,938
		Change in accounts payable			(74,001	)		36,605
		Change in other current liabilities			(25,927	)		(22,262	)
		Change in other assets and liabilities			(26,442	)		(47,196	)

			Net cash provided by operating activities		434,856			399,297
Investing activities:
	Capital/construction expenditures				(300,169	)		(264,327	)
	Allowance for equity funds used during construction				4,676			(1,025	)
	Investments in external decommissioning fund				(42,559	)		(38,921	)
	Other investments — net				(10,164	)		(6,565	)

			Net cash used in investing activities		(348,216	)		(310,838	)
Financing activities:
	Short-term borrowings — net				(140,804	)		155,996
	Proceeds from issuance of long-term debt				0			96,123
	Repayment of long-term debt, including reacquisition premiums				(1,073	)		(97,036	)
	Capital contributions from parent				184,934			0
	Dividends and cash distributions paid to parent				(123,292	)		(222,376	)

			Net cash used in financing activities		(80,235	)		(67,293	)
	Net increase in cash and cash equivalents				6,405			21,166
	Cash and cash equivalents at beginning of period				11,926			11,344

	Cash and cash equivalents at end of period			$	18,331		$	32,510

The Notes to Consolidated Financial Statements are an integral part of the Financial Statements.

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


			Sept. 30,			Dec. 31,
			2001			2000


			(Unaudited)
			(Thousands of Dollars)
ASSETS
Current assets:
	Cash and cash equivalents		$	18,331		$	11,926
	Accounts receivable — net of allowance for bad debts of $5,372 and $4,952, respectively			237,147			281,611
	Accounts receivable from affiliates			23,153			49,699
	Accrued unbilled revenues			115,692			194,547
	Materials and supplies inventories at average cost			107,278			103,863
	Fuel and gas inventories at average cost			52,163			51,775
	Prepayments and other			57,891			44,843

		Total current assets		611,655			738,264

Property, plant and equipment, at cost:
	Electric utility			6,542,173			6,388,697
	Gas utility			692,521			666,078
	Other and construction work in progress			581,269			531,678

		Total property, plant and equipment		7,815,963			7,586,453
	Less: accumulated depreciation			(4,229,342	)		(4,017,813	)
	Nuclear fuel — net of accumulated amortization of $999,772 and $967,928, respectively			85,077			86,499

		Net property, plant and equipment		3,671,698			3,655,139

Other assets:
	Nuclear decommissioning fund investments			552,617			563,812
	Other investments			26,995			24,892
	Regulatory assets			219,463			226,547
	Prepaid pension asset			168,279			107,784
	Other			58,658			43,550

		Total other assets		1,026,012			966,585

		Total Assets	$	5,309,365		$	5,359,988

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	303,884		$	303,773
	Short-term debt			218,385			359,189
	Accounts payable			213,819			303,053
	Accounts payable to affiliates			46,198			30,965
	Taxes accrued			161,576			130,870
	Dividends payable to parent			43,944			41,248
	Other			76,022			121,435

		Total current liabilities		1,063,828			1,290,533

Deferred credits and other liabilities:
	Deferred income taxes			672,730			678,849
	Deferred investment tax credits			84,979			91,088
	Regulatory liabilities			457,870			496,313
	Benefit obligations and other			140,258			146,541

		Total deferred credits and other liabilities		1,355,837			1,412,791

Long-term debt				1,043,863			1,048,995
Mandatorily redeemable preferred securities of subsidiary trust				200,000			200,000
Common stock — authorized 5,000,000 shares of $0.01 par value, outstanding 1,000,000 shares				10			10
Premium on common stock				664,321			479,387
Retained earnings				1,001,564			952,889
Leveraged shares held by ESOP at cost				(20,058	)		(24,617	)

		Total common stockholder’s equity		1,645,837			1,407,669
Commitments and contingent liabilities (see Note 5)

		Total Liabilities and Equity	$	5,309,365		$	5,359,988

The Notes to Consolidated Financial Statements are an integral part of the Financial Statements.

NSP-WISCONSIN

STATEMENTS OF INCOME



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

			2001		2000		2001		2000


			(Unaudited)
			(Thousands of Dollars)
Operating revenues:
	Electric utility		$	122,897	$	111,418	$	340,732	$	315,986
	Gas utility			9,088		10,284		96,615		63,672

		Total operating revenues		131,985		121,702		437,347		379,658
Operating expenses:
	Electric fuel and purchased power			65,534		53,844		185,049		159,949
	Cost of gas sold and transported			6,381		7,051		76,325		44,739
	Other operating and maintenance expenses			26,275		25,827		76,827		75,693
	Depreciation and amortization			10,285		10,422		30,807		30,759
	Taxes (other than income taxes)			4,032		3,801		12,065		11,691
	Special charges (see Note 2)			0		10,833		0		10,833

		Total operating expenses		112,507		111,778		381,073		333,664

Operating income				19,478		9,924		56,274		45,994
Other income — net				319		304		751		1,054
Interest charges and financing costs				5,542		4,731		16,383		14,077

Income before income taxes				14,255		5,497		40,642		32,971
Income taxes				5,628		3,654		15,509		14,332

Net income			$	8,627	$	1,843	$	25,133	$	18,639

The Notes to Financial Statements are an integral part of the Financial Statements.

NSP-WISCONSIN

STATEMENTS OF CASH FLOWS



				Nine Months Ended
				Sept. 30

				2001			2000


				(Unaudited)
				(Thousands of Dollars)
Operating activities:
	Net income			$	25,133		$	18,639
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			31,577			31,473
		Deferred income taxes			1,903			1,089
		Amortization of investment tax credits			(614	)		(620	)
		Allowance for equity funds used during construction			(1,111	)		(252	)
		Undistributed equity earnings of unconsolidated affiliates			(217	)		(259	)
		Change in accounts receivable			15,158			4,841
		Change in inventories			(1,005	)		102
		Change in other current assets			20,736			8,485
		Change in accounts payable			(36,228	)		(1,674	)
		Change in other current liabilities			1,918			4,031
		Change in other assets and liabilities			(6,762	)		(677	)

			Net cash provided by operating activities		50,488			65,178
Investing activities:
	Capital/construction expenditures				(45,842	)		(72,109	)
	Allowance for equity funds used during construction				1,111			252
	Other investments — net				(98	)		536

			Net cash used in investing activities		(44,829	)		(71,321	)
Financing activities:
	Short-term borrowings from affiliate — net				(8,700	)		(3,600	)
	Capital contributions from parent				25,000			29,977
	Dividends paid to parent				(21,959	)		(20,254	)

			Net cash provided by (used in) financing activities		(5,659	)		6,123

	Net increase (decrease) in cash and cash equivalents				0			(20	)
	Cash and cash equivalents at beginning of period				31			51

	Cash and cash equivalents at end of period			$	31		$	31

The Notes to Financial Statements are an integral part of the Financial Statements.

NSP-WISCONSIN

BALANCE SHEETS


			Sept. 30 2001			Dec. 31 2000


			(Unaudited)

			(Thousands of Dollars)
ASSETS
Current assets:
	Cash and cash equivalents		$	31		$	31
	Accounts receivable — net of allowance for bad debts of $1,282 and $798, respectively			38,289			53,447
	Accrued unbilled revenues			13,282			29,113
	Materials and supplies inventories at average cost			6,739			6,544
	Fuel and gas inventories at average cost			8,830			8,021
	Prepaid gross receipts tax			9,564			11,515
	Prepayments and other			1,498			4,451

		Total current assets		78,233			113,122

Property, plant and equipment, at cost:
	Electric utility			1,118,423			1,066,446
	Gas utility			127,486			123,979
	Other and construction work in progress			113,303			124,581

		Total property, plant and equipment		1,359,212			1,315,006
	Less: accumulated depreciation			(543,175	)		(515,745	)

		Net property, plant and equipment		816,037			799,261

Other assets:
	Other investments			10,183			9,867
	Regulatory assets			39,316			38,536
	Prepaid pension asset			25,907			18,561
	Other			3,288			6,728

		Total other assets		78,694			73,692

		Total Assets	$	972,964		$	986,075

LIABILITIES AND EQUITY
Current Liabilities:
	Current portion of long term debt		$	34		$	34
	Short-term debt — notes payable to affiliate			7,200			15,900
	Accounts payable			12,678			37,981
	Accounts payable to affiliates			13,343			25,202
	Interest accrued			7,230			5,570
	Dividend payable to parent			10,522			0
	Accrued payroll			5,063			8,395
	Purchased gas cost regulatory liability			3,093			390
	Other			5,628			5,596

		Total current liabilities		64,791			99,068

Deferred credits and other liabilities:
	Deferred income taxes			119,115			115,682
	Deferred investment tax credits			15,834			16,451
	Regulatory liabilities			17,683			18,818
	Benefit obligations and other			34,554			32,787

		Total other liabilities		187,186			183,738

Long-term debt				313,066			313,000
Common stock — authorized 1,000,000 shares of $100 par value, outstanding 933,000 shares				93,300			93,300
Premium on common stock				58,418			33,418
Retained earnings				256,203			263,551

		Total common stockholder’s equity		407,921			390,269

Commitments and contingent liabilities (see Note 5)
		Total Liabilities and Equity	$	972,964		$	986,075

The Notes to Financial Statements are an integral part of the Financial Statements.

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME



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

			2001			2000		2001			2000


			(Unaudited)

			(Thousands of Dollars)
Operating revenues:
	Electric utility		$	627,106		$	607,026	$	1,826,923		$	1,441,089
	Electric trading			315,708			247,330		1,035,988			394,215
	Gas utility			153,857			91,522		986,391			501,103
	Steam utility			1,325			1,372		11,790			7,094

		Total operating revenues		1,097,996			947,250		3,861,092			2,343,501
Operating expenses:
	Electric fuel and purchased power			399,083			378,281		1,083,319			773,795
	Electric trading costs			309,149			238,700		999,305			371,533
	Cost of gas sold and transported			97,038			35,024		762,422			296,015
	Steam costs			915			754		8,526			4,020
	Other operating and maintenance expenses			120,807			99,594		323,385			287,312
	Depreciation and amortization			59,088			49,921		175,369			152,171
	Taxes (other than income taxes)			9,273			19,340		53,151			61,149
	Special charges (see Note 2)			0			64,817		23,018			64,817

		Total operating expenses		995,353			886,431		3,428,495			2,010,812

Operating income				102,643			60,819		432,597			332,689
Other income (deductions) — net				(5,295	)		693		(4,207	)		4,563
Interest charges and financing costs:
	Interest charges — net of amount capitalized			26,976			38,393		86,147			111,401
	Distributions on redeemable preferred securities of subsidiary trust			3,800			3,800		11,400			11,400

		Total interest charges and financing costs		30,776			42,193		97,547			122,801

Income before income taxes				66,572			19,319		330,843			214,451
Income taxes				18,625			11,472		109,205			76,925

Net income			$	47,947		$	7,847	$	221,638		$	137,526

The Notes to Consolidated Financial Statements are an integral part of the Financial Statements.

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS



				Nine Months Ended
				Sept. 30

				2001			2000


				(Unaudited)
				(Thousands of Dollars)
Operating activities:
	Net income			$	221,638		$	137,526
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			181,566			157,674
		Deferred income taxes			(27,891	)		6,956
		Amortization of investment tax credits			(3,089	)		(3,370	)
		Allowance for equity funds used during construction			(526	)		0
		Write-off of post-employment costs			23,018			0
		Change in accounts receivable			63,580			(31,100	)
		Change in inventories			(22,610	)		(4,106	)
		Change in other current assets			261,549			(25,896	)
		Change in accounts payable			(266,476	)		120,922
		Change in other current liabilities			105,160			17,209
		Change in other assets and liabilities			(17,909	)		3,740

			Net cash provided by operating activities		518,010			379,555
Investing activities:
	Capital/construction expenditures				(294,307	)		(221,772	)
	Allowance for equity funds used during construction				526			0
	Payment received for notes receivable from affiliate				0			75,000
	Other investments — net				1,781			1,450

			Net cash used in investing activities		(292,000	)		(145,322	)
Financing activities:
	Short-term borrowings — net				105,075			(46,018	)
	Proceeds from issuance of long-term debt				100,000			97,314
	Repayment of long-term debt, including reacquisition premiums				(241,248	)		(172,293	)
	Dividends paid to parent				(166,922	)		(150,180	)

			Net cash used in financing activities		(203,095	)		(271,177	)

	Net increase (decrease) in cash and cash equivalents				22,915			(36,944	)
	Cash and cash equivalents at beginning of period				15,696			51,731

	Cash and cash equivalents at end of period			$	38,611		$	14,787

The Notes to Consolidated Financial Statements are an integral part of the Financial Statements.

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


			Sept. 30 2001			Dec. 31 2000


			(Unaudited)
			Thousands of Dollars)
ASSETS
Current assets:
	Cash and cash equivalents		$	38,611		$	15,696
	Accounts receivable — net of allowance for bad debts of $15,723 and $11,352, respectively			165,377			228,957
	Accrued unbilled revenues			255,713			369,018
	Recoverable purchased gas and electric energy costs			0			159,013
	Derivative instruments valuation — at market			49,295			0
	Materials and supplies inventories at average cost			40,455			41,106
	Fuel inventory at average cost			21,482			21,399
	Gas inventory — replacement cost in excess of LIFO: $36,829 and $106,790 respectively			67,990			44,812
	Prepayments and other			61,048			15,974

		Total current assets		699,971			895,975

Property, plant and equipment, at cost:
	Electric utility			5,155,163			4,896,863
	Gas utility			1,390,610			1,345,380
	Other and construction work in progress			841,322			876,332

		Total property, plant and equipment		7,387,095			7,118,575
	Less: accumulated depreciation			(2,713,054	)		(2,576,126	)

		Net property, plant and equipment		4,674,041			4,542,449

Other assets:
	Other investments			9,377			11,158
	Regulatory assets			204,710			251,154
	Prepaid pension assets			56,470			43,362
	Other			61,309			30,215

		Total other assets		331,866			335,889

		Total Assets	$	5,705,878		$	5,774,313




PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS — (Continued)
			Sept. 30		Dec. 31
			2001		2000


			(Unaudited)
			Thousands of Dollars)
LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	102,886	$	142,043
	Short-term debt			260,275		155,200
	Derivative instruments valuation — at market			46,207		0
	Accounts payable			301,153		575,948
	Accounts payable to affiliates			54,892		46,573
	Taxes accrued			127,503		54,718
	Dividends payable to parent			54,343		57,615
	Purchased gas and electric energy cost regulatory liability			72,778		27,060
	Other			132,965		146,309

		Total current liabilities		1,153,002		1,205,466

Deferred credits and other liabilities:
	Deferred income taxes			544,625		543,715
	Deferred investment tax credits			80,716		83,804
	Regulatory liabilities			49,085		45,027
	Other deferred credits			21,878		24,632
	Customer advances for construction			83,066		70,714
	Benefit obligations and other			88,352		73,028

		Total deferred credits and other liabilities		867,722		840,920

Long-term debt				1,509,153		1,610,741
Mandatorily redeemable preferred securities of subsidiary trust				194,000		194,000
Common stock — authorized 100 shares of $0.01 par value, outstanding 100 shares				0		0
Premium on common stock				1,574,835		1,574,835
Retained earnings				406,339		348,351
Accumulated other comprehensive income				827		0

		Total common stockholder’s equity		1,982,001		1,923,186

Commitments and contingent liabilities (see Note 5)
		Total Liabilities and Equity	$	5,705,878	$	5,774,313

The Notes to Consolidated Financial Statements are an integral part of the Financial Statements.

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF INCOME



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

			2001		2000			2001		2000


			(Unaudited)

			(Thousands of Dollars)
Electric utility operating revenues			$	387,219	$	319,530		$	1,088,173	$	792,404
Operating expenses:
	Electric fuel and purchased power			226,687		162,486			679,005		396,814
	Other operating and maintenance expenses			43,548		38,827			129,218		115,677
	Depreciation and amortization			20,697		19,345			61,506		58,063
	Taxes (other than income taxes)			10,608		10,988			35,684		34,843
	Special charges (see Note 2)			0		19,943			0		19,943

		Total operating expenses		301,540		251,589			905,413		625,340

Operating income				85,679		67,941			182,760		167,064
Other income — net				1,965		2,003			8,255		8,238
Interest charges and financing costs:
	Interest charges — net of amounts capitalized			9,319		14,246			34,207		41,331
	Distributions on redeemable preferred securities of subsidiary trust			1,963		1,963			5,888		5,888

		Total interest charges and financing costs		11,282		16,209			40,095		47,219

Income before income taxes and extraordinary item				76,362		53,735			150,920		128,083
Income taxes				28,653		21,844			56,860		49,290

Income before extraordinary item				47,709		31,891			94,060		78,793
Extraordinary item, net of tax (See Note 4)				0		(5,302	)		0		(18,960	)

Net income			$	47,709	$	26,589		$	94,060	$	59,833

The Notes to Financial Statements are an integral part of the Statements of Income.

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CASH FLOWS



				Nine Months Ended
				Sept. 30

				2001			2000


				(Unaudited)

				(Thousands of Dollars)
Operating activities:
	Net income			$	94,060		$	59,833
	Adjustments to reconcile net income to net cash provided by operating activities:
		Extraordinary item			0			18,960
		Depreciation and amortization			64,301			60,598
		Deferred income taxes			(19,144	)		37,312
		Amortization of investment tax credits			(188	)		(188	)
		Change in accounts receivable			(5,568	)		1,383
		Change in inventories			(632	)		5,556
		Change in other current assets			74,475			(156,346	)
		Change in accounts payable			(50,427	)		45,267
		Change in other current liabilities			27,418			839
		Change in other assets and liabilities			(14,860	)		(22,603	)

			Net cash provided by operating activities		169,435			50,611
Investing activities:
	Capital/construction expenditures				(93,445	)		(73,157	)
	Other investments — net				119,942			(6,316	)

			Net cash provided by (used in) investing activities		26,497			(79,473	)
Financing activities:
	Short-term borrowings — net				(135,173	)		477,023
	Repayment of long-term debt, including reacquisition premiums				168			(380,267	)
	Dividends paid to parent				(64,566	)		(65,699	)

			Net cash (used in) provided by financing activities		(199,571	)		31,057

	Net (decrease) increase in cash and cash equivalents				(3,639	)		2,195
	Cash and cash equivalents at beginning of period				10,826			1,532

	Cash and cash equivalents at end of period			$	7,187		$	3,727

The Notes to Financial Statements are an integral part of the Financial Statements.

SOUTHWESTERN PUBLIC SERVICE CO.

BALANCE SHEETS


			Sept. 30,			Dec. 31,
			2001			2000


			(Unaudited)
			(Thousands of Dollars)
ASSETS
Current assets:
	Cash and cash equivalents		$	7,187		$	10,826
	Accounts receivable — net of allowance for bad debts of $2,081 and $845, respectively			79,829			73,986
	Accounts receivable from affiliates			4,618			4,893
	Accrued unbilled revenues			88,079			87,484
	Recoverable electric energy costs			23,460			104,249
	Materials and supplies inventories at average cost			13,796			13,500
	Fuel and gas inventories at average cost			1,397			1,061
	Prepayments and other			5,757			38

		Total current assets		224,123			296,037

Property, plant and equipment, at cost:
	Electric utility			3,001,315			2,884,702
	Other and construction work in progress			88,505			115,210

		Total property, plant and equipment		3,089,820			2,999,912
	Less: accumulated depreciation			(1,258,793	)		(1,199,158	)

		Net property, plant and equipment		1,831,027			1,800,754

Other assets:
	Notes receivable from affiliate			0			119,036
	Other investments			11,389			12,295
	Regulatory assets			69,206			74,359
	Prepaid pension asset			77,220			61,359
	Other			33,659			28,796

		Total other assets		191,474			295,845

		Total Assets	$	2,246,624		$	2,392,636

LIABILITIES AND EQUITY
Current liabilities:
	Short-term debt		$	539,406		$	674,579
	Accounts payable			48,792			97,285
	Accounts payable to affiliates			11,173			13,107
	Taxes accrued			60,840			19,141
	Interest accrued			3,633			7,139
	Dividends payable to parent			20,534			22,354
	Current portion of accumulated deferred income taxes			10,628			36,307
	Derivative instruments valuation — at market			1,145			0
	Other			46,347			57,122

		Total current liabilities		742,498			927,034

Deferred credits and other liabilities:
	Deferred income taxes			363,378			362,206
	Deferred investment tax credits			4,530			4,718
	Regulatory liabilities			1,152			1,275
	Derivative instruments valuation — at market			5,792			0
	Benefit obligations and other			24,103			19,268

		Total deferred credits and other liabilities		398,955			387,467

Long-term debt				226,686			226,506
Mandatorily redeemable preferred securities of subsidiary trust				100,000			100,000
Common stock — authorized 200 shares of $1.00 par value, outstanding 100 shares				0			0
Premium on common stock				353,099			353,099
Retained earnings				429,845			398,530
Accumulated other comprehensive income (loss)				(4,459	)		0

		Total common stockholder’s equity		778,485			751,629
Commitments and contingent liabilities (see Note 5)

		Total Liabilities and Equity	$	2,246,624		$	2,392,636

The Notes to Financial Statements are an integral part of the Financial Statements.

NOTES TO FINANCIAL STATEMENTS

In the opinion of management, the accompanying unaudited consolidated and stand-alone financial statements contain all adjustments necessary to present fairly the financial position of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS (collectively referred to as the Utility Subsidiaries of Xcel Energy) as of Sept. 30, 2001, and Dec. 31, 2000, the results of their operations for the three months and nine months ended Sept. 30, 2001 and 2000, and their cash flows for the nine months ended Sept. 30, 2001 and 2000. Due to the seasonality of electric and gas sales of Xcel Energy’s Utility Subsidiaries, quarterly and year-to-date results are not necessarily an appropriate base from which to project annual results.

The accounting policies of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are set forth in Note 1 to the financial statements in their respective Annual Reports 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’s.

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 (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

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. Amounts reported for periods prior to the merger have been restated for comparability with post-merger treatment.

As part of the merger, NSP transferred its existing utility operations that were being conducted directly by NSP at the parent company level to a newly formed wholly-owned subsidiary of Xcel Energy named NSP-Minnesota. The results of NSP-Minnesota for periods prior to the merger have been restated for comparability with post-merger results. Xcel Energy has the following wholly owned public utility subsidiary companies that are Registrants reported herein: NSP-Minnesota, NSP-Wisconsin, PSCo and SPS.

2. Special Charges (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Merger Related —In 2000, Xcel Energy expensed pretax special charges related mainly to its regulated operations totaling $199 million. The total pretax charges included $52 million related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE. Also included in the total were $147 million of pretax charges pertaining to incremental costs of transition and integration activities associated with merging operations. Of the total pretax special charges recorded by Xcel Energy that related to its regulated operations, $159 million was recorded during the third quarter of 2000 and $40 million was recorded during the fourth quarter of 2000.

During 2000, an allocation of approximately $188 million of merger costs was made to Xcel Energy’s Utility Subsidiaries and is reported as special charges. This allocation was made to the various operating utility 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. 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.

NOTES TO FINANCIAL STATEMENTS — (Continued)

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


				Accrual
		Dec. 31, 2000		Adjustments		Payments			Sept. 30, 2001
		Liability		Expensed		Against Liability			Liability


		Millions of Dollars
Employee separation & other related costs		$	48		—	$	(36	)	$	12
Regulatory transition costs			5		—		(2	)		3
Other transition and integration costs			2		—		(2	)		—

	Total accrued merger costs — Xcel Energy	$	55		—	$	(40	)	$	15

NSP-Minnesota portion		$	19		—	$	(13	)	$	6
NSP-Wisconsin portion		$	3		—	$	(2	)	$	1
PSCo portion		$	2		—	$	(2	)	$	—
SPS portion		$	1		—		(1	)	$	—

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 of deferred postemployment benefit costs during the second quarter of 2001.

3. Business Developments (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

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.

NOTES TO FINANCIAL STATEMENTS — (Continued)

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.

NSP-Minnesota

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, relating to the authorization to store spent nuclear fuel in dry casks outside the Prairie Island nuclear plant, to develop 425 megawatts of Minnesota wind energy.

PSCo

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.

4. Restructuring and Regulation (NSP-Minnesota, NSP-Wisconsin and SPS)


	*NSP-Minnesota*

North Dakota Rate Case —In October 2000, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) to increase natural gas rates by approximately 3.3 percent, or $1.4 million, annually. In June 2001, the NDPSC approved an increase of approximately $860,000 annually.

NSP-Wisconsin

NSP-Wisconsin Electric Power Supply Rate Request —In May 2001, NSP-Wisconsin filed an application with the Public Service Commission of Wisconsin (PSCW), requesting an increase in its Wisconsin retail electric rates to recover significant increases in generating plant fuel and purchased power costs. On June 28, 2001, the PSCW approved an interim fuel cost surcharge that would have increased NSP-Wisconsin’s revenue by approximately $5.6 million for the last six months of 2001. On Oct. 18, 2001, the PSCW issued its final order on the interim fuel surcharge, which replaced the fuel surcharge with a corresponding increase in base electric rates.

NOTES TO FINANCIAL STATEMENTS — (Continued)

NSP-Wisconsin General Rate Case —On June 1, 2001, NSP-Wisconsin filed its required biennial rate application with the PSCW requesting no change in its Wisconsin retail electric and gas base rates. NSP-Wisconsin requested the PSCW to approve its application without hearing, pending completion of the staff’s audit. An order is expected by the end of the year.

Wisconsin Restructuring —The Wisconsin state budget included provisions that allow for the establishment of “leased generation contracts” between regulated utilities and their nonregulated generation affiliates organized as a Limited Liability Company (LLC). The provisions allow for a new approach in financing the cost of building new generating plants and allow for the transfer of utility property; however, existing generation facilities cannot be transferred. The legislative changes were necessary for Wisconsin Electric Power Company (WEPCo) to implement its proposed Power The Future 2 proposal it had filed with the PSCW.

In a parallel ruling, the PSCW took the first step in approving leased generation contracts by approving WEPCo’s declaratory ruling request for recovery of its pre-certification expenses related to the leased generation contracts. The PSCW’s October 2001 decision is viewed as the first of a number of PSCW approvals necessary, including future rulings on “need” established through the Certificate of Public Convenience and Necessity process and approval of the actual leased generation contract between the regulated utility and the nonregulated affiliate and all its financial components.

SPS

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 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

NOTES TO FINANCIAL STATEMENTS — (Continued)

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.

SPS Texas Retail Fuel Factor and Fuel Surcharge Application — SPS filed an application on Feb. 21, 2001, with the PUCT to increase its fixed fuel factor and to surcharge past fuel cost under-recoveries. Intervenors in the proceeding protested SPS’ application and claimed SPS should be crediting margins from certain wholesale firm sales to Texas retail eligible fuel expenses. Hearings were held in May 2001. A final decision was issued by the PUCT on Oct. 24, 2001. In this decision, the PUCT granted SPS’ request to account for wholesale firm sales through the base ratemaking process and to continue the practice of revenue crediting margins from non-firm sales to ratepayers as previously approved by the PUCT.


5.	Commitments and Contingent Liabilities (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

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’s Utility Subsidiaries have been or are currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, Xcel Energy’s Utility Subsidiaries are pursuing, or intend to pursue, insurance claims and believes it will recover some portion of these costs through such claims. Additionally, where applicable, Xcel Energy’s Utility Subsidiaries are pursuing, or intend 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’s Utility Subsidiaries would be required to recognize an expense for such unrecoverable amounts.

The circumstances set forth in Notes 12 and 13 to the financial statements in NSP-Minnesota’s, NSP-Wisconsin’s, PSCo’s and SPS’ Annual Reports 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.


	*NSP-Wisconsin*

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

NOTES TO FINANCIAL STATEMENTS — (Continued)

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 Financing Activities (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)


	*NSP-Minnesota*

At Sept. 30, 2001, NSP-Minnesota had approximately $218 million of short-term debt outstanding at a weighted average interest rate of 3.0 percent.

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 first quarter of 2002.


	*NSP-Wisconsin*

At Sept. 30, 2001, NSP-Wisconsin had approximately $7 million of short-term notes payable to NSP-Minnesota outstanding at a weighted average interest rate of 3.0 percent.


	*PSCo*

At Sept. 30, 2001, PSCo had approximately $260 million of short-term debt outstanding at a weighted average interest rate of 3.3 percent.


	*SPS*

At Sept. 30, 2001, SPS had approximately $539 million of short-term debt outstanding at a weighted average interest rate of 3.2 percent.

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.


7.	Segment Information (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Xcel Energy’s Utility Subsidiaries each have two reportable segments, Electric Utility and Gas Utility, with the exception of SPS, which has only an Electric Utility reportable segment. Trading operations are not a reportable segment; electric trading results are included in the Electric Utility segment.

NOTES TO FINANCIAL STATEMENTS — (Continued)

SPS operates in the regulated electric utility industry, providing wholesale and retail electric service in the states of Texas, New Mexico, Kansas and Oklahoma. Revenues from external customers were $387.2 million and $319.5 million for the three months ended Sept. 30, 2001 and 2000, respectively. Revenues from external customers were $1,088.2 million and $ 792.4 million for the nine months ended Sept. 30, 2001 and 2000, respectively.

All figures are in thousands of dollars.


	*NSP-Minnesota*


		Electric		Gas						Consolidated
		Utility		Utility			All Other			Total

Three months ended:
Sept. 30, 2001
Revenues from:
External customers		$	765,421	$	51,689		$	—		$	817,110
Internal customers			186		2			—			188

	Total revenue		765,607		51,691			—			817,298
Segment net income		$	80,381	$	(4,201	)	$	(90	)	$	76,090
Sept. 30, 2000
Revenues from:
External customers		$	696,112	$	62,223		$	—		$	758,335
Internal customers			178		2,518			—			2,696

	Total revenue		696,290		64,741			—			761,031
Segment net income		$	31,686	$	(6,523	)	$	—		$	25,163
Nine months ended:
Sept. 30, 2001
Revenues from:
External customers		$	2,033,549	$	497,215		$	—		$	2,530,764
Internal customers			532		146			—			678

	Total revenue		2,034,081		497,361			—			2,531,442
Segment net income		$	161,171	$	13,833		$	(341	)	$	174,663
Sept. 30, 2000
Revenues from:
External customers		$	1,807,426	$	298,489		$	—		$	2,105,915
Internal customers			493		1,522			—			2,015

	Total revenue		1,807,919		300,011			—			2,107,930
Segment net income		$	75,611	$	6,660		$	—		$	82,271

NOTES TO FINANCIAL STATEMENTS — (Continued)


	*NSP-Wisconsin*


		Electric		Gas					Consolidated
		Utility		Utility			All Other		Total

Three months ended:
Sept. 30, 2001
Revenues from:
External customers		$	122,862	$	8,565		$	—	$	131,427
Internal customers			35		523			—		558

	Total revenue		122,897		9,088			—		131,985
Segment net income		$	10,643	$	(2,016	)	$	—	$	8,627
Sept. 30, 2000
Revenues from:
External customers		$	111,387	$	9,770		$	—	$	121,157
Internal customers			31		514			—		545

	Total revenue		111,418		10,284			—		121,702
Segment net income		$	3,887	$	(2,044	)	$	—	$	1,843
Nine months ended:
Sept. 30, 2001
Revenues from:
External customers		$	340,604	$	95,200		$	—	$	435,804
Internal customers			128		1,415			—		1,543

	Total revenue		340,732		96,615			—		437,347
Segment net income		$	22,172	$	2,961		$	—	$	25,133
Sept. 30, 2000
Revenues from:
External customers		$	315,879	$	62,076		$	—	$	377,955
Internal customers			107		1,596			—		1,703

	Total revenue		315,986		63,672			—		379,658
Segment net income		$	17,742	$	897		$	—	$	18,639


	*PSCo*


		Electric		Gas				Consolidated
		Utility		Utility		All Other		Total

Three months ended:
Sept. 30, 2001
Revenues from:
External customers		$	942,783	$	153,300	$	1,325	$	1,097,408
Internal customers			31		557		—		588

	Total revenue		942,814		153,857		1,325		1,097,996
Segment net income		$	44,482	$	178	$	3,287	$	47,947

NOTES TO FINANCIAL STATEMENTS — (Continued)


		Electric		Gas					Consolidated
		Utility		Utility			All Other		Total

Sept. 30, 2000
Revenues from:
External customers		$	854,356	$	91,522		$	1,372	$	947,250
Internal customers			—		—			—		—

	Total revenue		854,356		91,522			1,372		947,250
Segment net income		$	7,633	$	(11,390	)	$	11,604	$	7,847
Nine months ended:
Sept. 30, 2001
Revenues from:
External customers		$	2,862,814	$	984,711		$	11,790	$	3,859,315
Internal customers			97		1,680			—		1,777

	Total revenue		2,862,911		986,391			11,790		3,861,092
Segment net income		$	171,835	$	27,503		$	22,300	$	221,638
Sept. 30, 2000
Revenues from:
External customers		$	1,835,304	$	501,103		$	7,094	$	2,343,501
Internal customers			—		—			—		—

	Total revenue		1,835,304		501,103			7,094		2,343,501
Segment net income		$	100,418	$	13,468		$	23,640	$	137,526

8. Adoption of SFAS 133 (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

On Jan. 1, 2001, Xcel Energy’s Utility Subsidiaries 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 on 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 any 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.

Xcel Energy’s Utility Subsidiaries have applied SFAS 133 to 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 to 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.

NOTES TO FINANCIAL STATEMENTS — (Continued)

Xcel Energy conducts energy acquisition, wholesale sales and trading activities through its utility operations. The primary objective of Xcel Energy’s energy acquisition and trading operations is to maximize asset value while minimizing pricing and credit risks. These activities are subject to SFAS 133 as they typically meet the definition of derivative instruments. For the Xcel Energy’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.

Xcel Energy’s Utility Subsidiaries formally document 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’s Utility Subsidiaries also formally assess both at inception and at least quarterly thereafter, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash flows of the hedged items.

The adoption of SFAS 133 on Jan. 1, 2001, by Xcel Energy’s Utility Subsidiaries did not impact earnings. However, upon adoption of SFAS 133, PSCo and SPS recorded net transition gains/ (losses) of approximately $1.6 million and $(2.6) million, respectively, which were recorded in other comprehensive income. The impact to other comprehensive income is related to existing cash flow hedges during increasing price conditions. The adoption of SFAS 133 does not impact NSP-Minnesota or NSP-Wisconsin.

The impact of SFAS 133 on Xcel Energy’s Utility Subsidiaries other comprehensive income is detailed in the following table (in millions of dollars).


	PSCo			SPS

Net transition gain (loss), Jan. 1, 2001	$	1.6		$	(2.6	)
After-tax net unrealized losses related to derivatives accounted for as hedges		(27.0	)		(2.2	)
After-tax net realized losses on derivative transactions reclassified into earnings		26.2			0.4

Other comprehensive income (loss), Sept. 30, 2001	$	0.8		$	(4.4	)

PSCo’s earnings for the first nine months of 2001 decreased by approximately $1 million (before tax).

Energy and energy related commodities — PSCo is exposed to commodity price variability and credit risk in its generation and retail distribution. To manage these commodity price risks, PSCo 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 PSCo are accounted for as cash flow hedges and recorded as electric fuel and purchased power.

PSCo 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.

At Sept. 30, 2001, PSCo had various commodity-related contracts extending through December 2002. PSCo expects to reclassify into earnings during the next 12 months net gains from other comprehensive income of approximately $1.8 million.

Interest rates — To manage interest rate risk, SPS 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. SPS expects to reclassify into earnings during the next 12 months net losses from other comprehensive income of approximately $0.7 million.

NOTES TO FINANCIAL STATEMENTS — (Continued)

Cash flow hedge quantitative disclosures —The gain (loss) recognized in earnings for derivative instruments that have been designated and qualify as cash flow hedges 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 (PSCo)	$	—		$	(1.2	)	$	—
	Interest rates (SPS)		—			—			—
Nine months ended Sept. 30, 2001:
	Energy and energy related commodities (PSCo)	$	(1.0	)	$	—		$	0.02
	Interest rates (SPS)		—			—			—

9. Comprehensive Income (NSP-Minnesota, NSP-Wisconsin, PSCo, SPS)

NSP-Minnesota and NSP-Wisconsin

For NSP-Minnesota and NSP-Wisconsin comprehensive income equals net income for the quarters and year-to-date periods ended Sept. 30, 2001 and 2000.

PSCo

The components of total comprehensive income are shown below:



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

		2001		2000		2001			2000


		(Thousands of Dollars)
Net income		$	47,947	$	7,847	$	221,638		$	137,526
Other comprehensive income:
	Cumulative effect of accounting change-SFAS 133		—		—		1,649			—
	Net gains (losses) on derivatives (see Note 8)		925		—		(822	)		—

Other comprehensive income			925		—		827			—

Comprehensive income		$	48,872	$	7,847	$	222,465		$	137,526

The accumulated comprehensive income in stockholder’s equity at Sept. 30, 2001, relates to valuation adjustments on derivative financial instruments and hedging activities.

NOTES TO FINANCIAL STATEMENTS — (Continued)

SPS

The components of total comprehensive income are shown below:



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

		2001		2000		2001			2000


		(Thousands of Dollars)
Net income		$	47,709	$	26,589	$	94,060		$	59,833
Other comprehensive income:
	Cumulative effect of accounting change-SFAS 133		—		—		(2,626	)		—
	Net gains (losses) on derivatives (see Note 8)		346		—		(1,833	)		—

Other comprehensive income (loss)			346		—		(4,459	)		—

Comprehensive income		$	48,055	$	26,589	$	89,601		$	59,833

The accumulated comprehensive loss in stockholder’s equity at Sept. 30, 2001, relates to valuation adjustments on derivative financial instruments and hedging activities.

REPORTS OF INDEPENDENT PUBLIC ACCOUNTANTS

To Northern States Power Company — Minnesota:

We have reviewed the accompanying consolidated balance sheet of Northern States Power Company — Minnesota (a Minnesota corporation) and subsidiaries as of September 30, 2001, the related consolidated statements of income for the three and nine-month periods ended September 30, 2001 and 2000, and the consolidated statements of cash flows for the nine-month periods ended September 30, 2001 and 2000. These financial statements are the responsibility of the Company’s management.

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, 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 consolidated balance sheet of Northern States Power Company — Minnesota 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

To Northern States Power Company — Wisconsin:

We have reviewed the accompanying balance sheet of Northern States Power Company — Wisconsin (a Wisconsin corporation) as of September 30, 2001, the related statements of income for the three and nine month periods ended September 30, 2001 and 2000, and the statements of cash flows for the nine-month periods ended September 30, 2001 and 2000. These financial statements are the responsibility of the Company’s management.

Based on our review, we are not aware of any material modifications that should be made to the 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 Northern States Power Company — Wisconsin 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 balance sheet as of December 31, 2000, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.


	ARTHUR ANDERSEN LLP

Minneapolis, Minnesota

November 13, 2001

To Public Service Company of Colorado:

We have reviewed the accompanying consolidated balance sheet of Public Service Company of Colorado (a Colorado corporation) and subsidiaries as of September 30, 2001, the related consolidated statements of income for the three and nine-month periods ended September 30, 2001 and 2000, and the consolidated statements of cash flows for the nine-month periods ended September 30, 2001 and 2000. These financial statements are the responsibility of the Company’s management.

We have previously audited, in accordance with auditing standards generally accepted in the United States, the consolidated balance sheet of Public Service Company of Colorado 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

To Southwestern Public Service Company:

We have reviewed the accompanying balance sheet of Southwestern Public Service Company (a New Mexico corporation) as of September 30, 2001, the related statements of income for the three and nine-month periods ended September 30, 2001 and 2000, and the statements of cash flows for the nine-month periods ended September 30, 2001 and 2000. These financial statements are the responsibility of the Company’s management.

We have previously audited, in accordance with auditing standards generally accepted in the United States, the balance sheet of Southwestern Public Service Company 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 balance sheet as of December 31, 2000, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.


	ARTHUR ANDERSEN LLP

Minneapolis, Minnesota

November 13, 2001

Item 2. Management’s Discussion and Analysis

Discussion of financial condition and liquidity for the Utility Subsidiaries of Xcel Energy are omitted per conditions set forth in general instructions H(1)(a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations as set forth in general instructions H(2)(a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

Forward-Looking Information

The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of Xcel Energy’s Utility Subsidiaries 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 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,” “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’s utility 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 the Utility Subsidiaries of Xcel Energy;

	•	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;

	•	risks associated with the California power markets; and

	•	the other risk factors listed from time to time by the Utility Subsidiaries of 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.

Market Risks

The Utility Subsidiaries of Xcel Energy 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 their annual reports on Form 10-K for the year ended Dec. 31, 2000. Commodity price and interest rate risks for the Utility Subsidiaries of Xcel Energy 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.

Pending Accounting Changes

SFAS 142 — In June 2001, the Financial Accounting Standards Board (FASB) approved the issuance of Statement of Financial Accounting Standard (SFAS) No. 142 — “Accounting for Goodwill and Other Intangible Assets.” This statement will require different accounting for intangible assets compared to goodwill. Intangible assets will be amortized over their economic useful life and reviewed for impairment in accordance with SFAS 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.

NSP-Minnesota, NSP-Wisconsin, PSCo and SPS have immaterial amounts of unamortized intangible assets and no amounts of goodwill as of Sept. 30, 2001. Consequently, the adoption of SFAS 142 as required as of Jan. 1, 2002 is expected to have an immaterial or no effect on the results of operations or financial position of those companies.

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

NSP-Minnesota 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, NSP-Minnesota recorded and recovered in rates $583 million of decommissioning obligations and had total estimated discounted decommissioning cost obligations of $838 million.

If NSP-Minnesota 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 the accrued plant removal costs for other generation, transmission and distribution facilities of all of the utility subsidiaries. We expect 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’s Utility Subsidiaries expect 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, the Utility Subsidiaries of Xcel Energy will be required to measure discontinued operations at the lower of 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 the Utility Subsidiaries of 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.

NSP-MINNESOTA’S MANAGEMENT’S DISCUSSION AND ANALYSIS

Results of Operations

NSP-Minnesota’s net income was approximately $174.7 million for the first nine months of 2001, compared with approximately $82.3 million for the first nine months of 2000.

Special Charges

During the first nine months of 2000, NSP-Minnesota expensed pretax special charges totaling approximately $59.1 million. The pretax charges included expenses related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE and incremental costs of transition and integration activities associated with the merger.

Conservation Incentive Recovery

Earnings for the first nine months of 2001 were increased 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. NSP-Minnesota recorded a $35 million charge in 1999 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. 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.

Electric Utility Margins

The following table details the change in electric 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 and the ability to vary wholesale prices with changing market conditions, most fluctuations in energy costs do not affect electric margin. However, the fuel clause cost recovery in the Minnesota, North Dakota and South Dakota

jurisdictions does not allow for complete recovery of all purchased power expenses and, therefore, higher purchased power costs, particularly in periods of extreme temperatures, can adversely affect earnings.



		Nine Months Ended
		Sept. 30

		2001		2000


		(Millions of Dollars)
Electric retail, firm wholesale and other revenue		$	1,906	$	1,691
Short-term wholesale revenue			128		117

	Total electric utility revenue		2,034		1,808
Electric retail and firm wholesale fuel and purchased power			713		553
Short-term wholesale fuel and purchased power			94		84

	Total electric utility fuel and purchased power		807		637
Electric retail, firm wholesale and other margin			1,193		1,138
Short-term wholesale margin			34		33

	Total electric utility margin	$	1,227	$	1,171

Electric revenue increased by approximately $226 million, or 12.5 percent, in the first nine months of 2001, compared with the first nine months of 2000. Electric margin increased by approximately $56 million, or 4.8 percent, in the first nine months of 2001, compared with the first nine months of 2000. The increase in retail revenue was primarily due to an increase in purchased power costs recovered in electric rates. 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. 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. Additionally, more favorable temperatures during the first nine months of 2001 increased retail revenue by approximately $27 million and retail margin by approximately $22 million. Retail revenue and margin were reduced by approximately $7 million in the first nine months of 2001 due to a rate reduction in Minnesota agreed to as part of the Xcel Energy merger approval process. A portion of the increase in revenue and margin was also attributed to the shared trading margins from the Joint Operating Agreement (JOA) for the operating utilities of Xcel Energy. The JOA was approved and placed into effect by the Federal Energy Regulatory Commission as part of the NSP/ NCE Merger in August 2000.

Gas Utility Margins

The following table details the change in gas revenue and margin. The cost of gas tends to vary with changing sales requirements and 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 gas margin.



	Nine Months Ended
	Sept. 30

	2001			2000


	(Millions of Dollars)
Gas revenue	$	497		$	300
Cost of gas purchased and transported		(393	)		(200	)

Gas margin	$	104		$	100

Gas revenue for the first nine months of 2001 increased by approximately $197 million, or 65.7 percent, compared with the first nine months of 2000, largely due to recovery of the higher cost of gas. Gas margin for the first nine months of 2001 increased by $4 million, or 4.0 percent, compared with the first nine months of 2000. Cooler winter temperatures increased gas sales in the first nine months of 2001, increasing gas revenues by approximately $27 million and gas margins by approximately $9 million. The favorable increase in margin due to weather was partially offset by a revision to estimated purchased gas recovery accruals in Minnesota.

Non-Fuel Operating Expense and Other Costs

Other Operating and Maintenance Expense increased by approximately $25 million, or 4.5 percent, for the first nine months of 2001, compared with the first nine months of 2000. The change is largely due to timing of plant outages, increased bad debt reserves resulting from higher energy prices and increased nuclear costs to establish the Nuclear Management Co. and to maintain and improve operational excellence at the nuclear plants.

Depreciation and Amortization Expense increased by approximately $7 million, or 3.0 percent, for the first nine months of 2001, compared with the first nine months of 2000, primarily due to increased capital additions to utility plant.

Interest charges and financing costs decreased by approximately $28 million, or 26.5 percent, for the first nine months of 2001, compared with the first nine months of 2000. The change is largely due to lower average debt levels and lower short-term interest rates.

NSP-WISCONSIN’S MANAGEMENT’S DISCUSSION AND ANALYSIS

Results of Operations

NSP-Wisconsin’s net income was approximately $25.1 million for the first nine months of 2001, compared with approximately $18.6 million for the first nine months of 2000.

Special Charges

During the first nine months of 2000, NSP-Wisconsin expensed pretax special charges totaling approximately $10.8 million. The pretax charges included expenses related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE and incremental costs of transition and integration activities associated with the merger.

Electric Utility Margins

The following table details the change in electric revenue and margin. Electric production expenses tend to vary with the quantity of electricity required and changes in the unit costs of fuel and purchased power. The fuel and purchased power cost recovery mechanism of the Wisconsin jurisdiction does not allow for complete recovery of all expenses and, therefore, dramatic changes in costs or periods of extreme temperatures can adversely affect earnings.



		Nine Months Ended
		Sept. 30

		2001			2000


		(Millions of Dollars)
Electric retail, wholesale and other revenue		$	341		$	316
Electric retail and wholesale fuel and purchased power			(185	)		(160	)

	Total electric utility margin	$	156		$	156

Electric revenue increased by approximately $25 million, or 7.9 percent, in the first nine months of 2001, compared with the first nine months of 2000. Revenue increased primarily because of rate and cost-sharing mechanisms that passed through some of the effects of higher electricity production costs to NSP-Wisconsin’s customers. The primary causes of the increase in fuel and purchased power expenses were higher generating plant fuel costs and greater and more expensive purchases of power from other parties.

Gas Utility Margins

The following table details the change in gas revenue and margin. The cost of gas tends to vary with the amount of gas purchased and the unit cost of gas purchases. However, purchased gas cost recovery

mechanisms allow NSP-Wisconsin to pass through changes in the cost of natural gas to retail customers, so fluctuations in the cost of gas have little effect on gas margin.



	Nine Months Ended
	Sept. 30

	2001			2000


	(Millions of Dollars)
Gas revenue	$	97		$	64
Cost of gas purchased and transported		(76	)		(45	)

Gas margin	$	21		$	19

Natural gas revenue for the first nine months of 2001 increased by $33 million, or 51.6 percent, over the first nine months of 2000, mostly due to recovery of the higher natural gas costs for the first nine months of 2001. Gas revenue and margin also increased, due to more favorable weather conditions, which increased gas sales.

Non-Fuel Operating Expense and Other Costs

Interest charges were $2.3 million greater during the first nine months of 2001 than they were during the first nine months of 2000. The increase was primarily because $80 million of new debt had been issued in October 2000 and part of the proceeds had been used to pay off short-term debt owed to its affiliate, NSP-Minnesota.

PSCo’S MANAGEMENT’S DISCUSSION AND ANALYSIS

Results of Operations

PSCo’s net income was approximately $221.6 million for the first nine months of 2001, compared with approximately $137.5 million for the first nine months of 2000.

Special Charges

During the first nine months of 2000, PSCo expensed pretax special charges totaling approximately $63.1 million. The pretax charges included expenses related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE and incremental costs of transition and integration activities associated with the merger.

Earnings for the first nine months of 2001 were decreased, 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.

Electric Utility Margins

The following table details the change in electric 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. 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 addition to the ICA, PSCo has other adjustment clauses that allow certain costs to be passed through to retail customers. The Qualifying Facilities Capacity Cost Adjustment (QFCCA) provides for recovery of purchased capacity costs from certain Qualifying Facilities projects not otherwise reflected in base electric rates. The fuel clause

cost recovery does not allow for complete recovery of all purchased energy costs and capacity costs and, therefore, higher costs can adversely affect earnings.



		Nine Months Ended
		Sept. 30

		2001		2000


		(Millions of Dollars)
Electric retail and firm wholesale revenue		$	1,283	$	1,193
Short-term wholesale revenue			544		248

	Total electric utility revenue		1,827		1,441
Electric retail and firm wholesale fuel and purchased power			650		562
Short-term wholesale fuel and purchased power			433		212

	Total electric utility fuel and purchased power		1,083		774
Electric retail and firm wholesale margin			633		631
Short-term wholesale margin			111		36

	Total electric utility margin	$	744	$	667

Electric revenue increased by approximately $386 million, or 26.8 percent, in the first nine months of 2001, compared with the first nine months of 2000. Electric margin increased by approximately $77 million, or 11.5 percent, in the first nine months of 2001, compared with the first nine months of 2000. Retail margin was relatively flat for the first nine months of 2001. Increases in retail margin due to sales growth, were partially offset by increased fuel and purchased power costs, which are not completely recoverable from customers in Colorado due to cost sharing under various cost recovery mechanisms. Retail revenue and margin were also reduced by approximately $6 million for the first nine months of 2001, due to a rate reduction in Colorado agreed to as part of the Xcel Energy merger approval process.

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

Gas Utility Margins

The following table details the change in gas revenue and margin. The cost of gas tends to vary with changing sales requirements and unit cost of gas purchases. PSCo has a Gas Cost Adjustment mechanism for natural gas sales, which recognizes the majority of the effects of changes in the cost of gas purchased for resale and adjusts revenues to reflect such changes in costs on a timely basis. Therefore, fluctuations in the cost of gas have little effect on gas margin.



	Nine Months Ended
	Sept. 30

	2001			2000


	(Millions of Dollars)
Gas revenue	$	986		$	501
Cost of gas purchased and transported		(762	)		(296	)

Gas margin	$	224		$	205

Gas revenue for the first nine months of 2001 increased by approximately $485 million, or 96.8 percent, compared with the first nine months of 2000, largely due to recovery of the higher cost of gas. Gas margin for the first nine months of 2001 increased by approximately $19 million, or 9.3 percent, compared with the first nine months of 2000. More favorable temperatures during the first nine months of 2001 increased gas revenue by approximately $32 million and gas margin by approximately $11 million. Margin was also increased due to higher rates from a 2000 rate case, effective Feb. 1, 2001.

Electric Trading Margins

Trading revenues and cost of sales do not include the revenue and production costs associated with energy produced from generation assets or energy and capacity purchased to serve native load. The following table details the changes in electric trading revenue and margin. Trading margins reflect the impact of the sharing certain trading margins under the ICA.



	Nine Months Ended
	Sept. 30

	2001			2000


	(Millions of Dollars)
Trading revenue	$	1,036		$	394
Trading cost of sales		(999	)		(372	)

Trading margin	$	37		$	22

Trading revenue increased by approximately $642 million and trading margin increased by approximately $15 million for the first nine months of 2001, compared with the first nine months of 2000. The increase in trading revenue and margin is a result of the expansion of PSCo’s electric trading operation and favorable market conditions, including strong prices in the western markets. It is not expected that trading margins for the remainder of 2001 and 2002 will be as strong, due to softer energy market conditions and a decline in the forward energy price curve. Trading revenue and margin were reduced under the provisions of the JOA for the operating utilities of Xcel Energy. The JOA requires certain PSCo trading margins to be shared with NSP-Minnesota and SPS.

Non-Fuel Operating Expense and Other Costs

Other Operation and Maintenance Expense increased by approximately $36.1 million, or 12.6 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 costs due to customer growth and generation maintenance overhauls.

Depreciation and Amortization Expense increased by approximately $23.2 million, or 15.2 percent, for the first nine months of 2001, compared with the first nine months of 2000, primarily due to increased amortization costs of software and increased depreciation resulting from capital additions to utility plant.

Taxes Other Than Income decreased by approximately $8 million, or 13.1 percent, for the first nine months of 2001, compared with the first nine months of 2000, primarily due to the timing of a property tax refund from calendar year 2000.

Other income — net of deductions for the first nine months of 2001 decreased primarily due to higher nonutility costs in 2001 and higher interest income from a note receivable during the first nine months of 2000. The note receivable was paid off in late 2000 and the cash proceeds were used to lower short-term borrowings. The decrease was partially offset by a $11 million gain on the sale of the Boulder Hydro facility recorded in the first nine months of 2001.

Interest expense decreased by approximately $25.3 million, or 22.7 percent, for the first nine months of 2001, compared with the first nine months of 2000. The decrease was primarily due to lower interest rates and lower debt levels.

SPS’ MANAGEMENT’S DISCUSSION AND ANALYSIS

Results of Operations

SPS’ net income was approximately $94.1 million for the first nine months of 2001, compared with approximately $59.8 million for the first nine months of 2000.

Special Charges

During the first nine months of 2000, SPS expensed pretax special charges totaling approximately $19.9 million. The pretax charges included expenses related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE and incremental costs of transition and integration activities associated with the merger.

Extraordinary Item — Electric Utility Restructuring

During the second quarter of 2000, SPS wrote off its generation-related regulatory assets and other deferred costs for an extraordinary charge of approximately $19.3 million before tax, or $13.7 million after tax. During the third quarter of 2000, SPS recorded an additional extraordinary charge of $8.2 million before tax, or $5.3 million after tax, related to the tender offer/defeasance of approximately $295 million of first mortgage bonds. For more information on restructuring, including the reapplication of regulatory accounting under SFAS 71, see Note 4 to the Financial Statements.

Electric Utility Margins

The following table details the change in electric 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. Fuel and purchased power costs are recoverable in SPS’ Texas jurisdiction through a fixed fuel factor, which is included in rates. In the New Mexico retail jurisdiction, fuel and purchased energy costs are adjusted through a fuel clause and a fixed annual factor. In all other jurisdictions, SPS currently recovers substantially all increases and refunds substantially all decreases in fuel and purchased power costs pursuant to monthly adjustment clauses. Due to these fuel clause cost recovery mechanisms for retail customers and the ability to vary wholesale prices with changing market conditions, most fluctuations in energy costs do not affect electric margin. However, the fuel clause cost recovery does not allow for complete recovery of all variable production expenses and, therefore, higher costs can adversely affect earnings.



		Nine Months Ended
		Sept. 30

		2001		2000


		(Millions of Dollars)
Electric retail, firm wholesale and other revenue		$	1,086	$	786
Short-term wholesale revenue			2		6

	Total electric utility revenue		1,088		792
Electric retail and firm wholesale fuel and purchased power			678		393
Short-term wholesale fuel and purchased power			1		4

	Total electric utility fuel and purchased power		679		397
Electric retail, firm wholesale and other margin			408		393
Short-term wholesale margin			1		2

	Total electric utility margin	$	409	$	395

Electric revenue increased by approximately $296 million, or 37.3 percent, for the first nine months of 2001, compared with the first nine months of 2000. Electric margin increased by approximately $14 million, or 3.5 percent, for the first nine months of 2001, compared with the first nine months of 2000. Electric revenues increased for the first nine months of 2001, largely due to increased transmission revenue, more favorable

temperatures and customer growth. Retail revenue and margin were reduced by approximately $3 million for the first nine months of 2001, due to rate reductions in Texas and New Mexico agreed to as part of the merger approval process.

Non-Fuel Operating Expense and Other Costs

Other Operation and Maintenance Expense increased by approximately $13.5 million, or 11.7 percent, for the first nine months of 2001, compared with the first nine months of 2000. The change is largely due to increased transmission costs from the Southwest Power Pool (which are offset by increased electric revenue) and increased bad debt reserves resulting from higher energy prices.

Depreciation and Amortization Expense increased by approximately $3.4 million, or 5.9 percent, for the first nine months of 2001, compared with the first nine months of 2000, primarily due to increased depreciation from capital additions to utility plant.

Interest expense decreased by approximately $7.1 million, or 15.1 percent, for the first nine months of 2001, compared with the first nine months of 2000. The change is largely due to lower interest expense resulting from the use of more short-term debt until the issuance of long-term debt in October 2001.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against the Utility Subsidiaries of 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 NSP-Minnesota’s, NSP-Wisconsin’s, PSCo’s and SPS’ 2000 Form 10-K for a description of certain legal proceedings presently pending. There are no new significant cases to report against the Utility Subsidiaries of Xcel Energy and there have been no notable changes in the previously reported proceedings, except as set forth below.

NSP-Minnesota

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.

NSP-Wisconsin

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 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.

PSCo

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:


15.01		Letter from Arthur Andersen LLP regarding unaudited interim information for NSP-Minnesota.
15.02		Letter from Arthur Andersen LLP regarding unaudited interim information for PSCo.
15.03		Letter from Arthur Andersen LLP regarding unaudited interim information for SPS.
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:

NSP-Minnesota

June 28, 2001 (filed July 17, 2001) Item 5: Other Events. Re: Disclosure of reversal of MPUC decision to deny recovery of NSP-Minnesota’s conservation incentives.

NSP-Wisconsin

None.

PSCo

July 2, 2001 (filed July 17, 2001) Item 5: Other Events. Re: Colorado Supreme Court decision denying PSCo recovery of deferred costs for employees’ postemployment benefits.

SPS

Oct. 23, 2001 (filed Oct., 24, 2001) — Item 5 and 7. Other Events and Exhibits. Re: Disclosure of SPS $500 million bond offering.

NORTHERN STATES POWER CO. (A MINNESOTA CORPORATION) SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on Nov. 13, 2001.


	NORTHERN STATES POWER CO.
	(a Minnesota corporation)
	(Registrant)


	By:	/s/


	David E. Ripka
	Vice President and Controller


	By:	/s/


	Edward J. McIntyre
	Vice President and Chief Financial Officer

NORTHERN STATES POWER CO. (A WISCONSIN CORPORATION) SIGNATURES


	NORTHERN STATES POWER CO.
	(a Wisconsin corporation)
	(Registrant)


	By:	/s/


	David E. Ripka
	Vice President and Controller


	By:	/s/


	Edward J. McIntyre
	Vice President and Chief Financial Officer

PUBLIC SERVICE CO. OF COLORADO SIGNATURES


	PUBLIC SERVICE CO. OF COLORADO
	(Registrant)


	By:	/s/


	David E. Ripka
	Vice President and Controller


	By:	/s/


	Edward J. McIntyre
	Vice President and Chief Financial Officer

SOUTHWESTERN PUBLIC SERVICE CO.


	SOUTHWESTERN PUBLIC SERVICE CO.
	(Registrant)


	By:	/s/


	David E. Ripka
	Vice President and Controller


	By:	/s/


	Edward J. McIntyre
	Vice President and Chief Financial Officer

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Public Service Co Of Colorado 10-Q2001 Q3 Quarterly report

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