NORTHERN STATES POWER CO /WI/ - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

		For the quarterly period ended Sept. 30, 2002

		OR

[ ]		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 jurisdiction of incorporation or organization, Address of
Commission	principal executive offices and Registrant’s Telephone Number,	IRS Employer
File Number	including area code	Identification No.

000-31709	NORTHERN STATES POWER COMPANY	41-1967505
	(a Minnesota Corporation)
	414 Nicollet Mall, Minneapolis, Minn. 55401
	Telephone (612) 330-5500

001-3140	NORTHERN STATES POWER COMPANY	39-0508315
	(a Wisconsin Corporation)
	1414 W. Hamilton Ave., Eau Claire, Wis. 54701
	Telephone (715) 839-2625

001-3280	PUBLIC SERVICE COMPANY OF COLORADO	84-0296600
	(a Colorado Corporation)
	1225 17th Street, Denver, Colo. 80202
	Telephone (303) 571-7511

001-3789	SOUTHWESTERN PUBLIC SERVICE COMPANY	75-0575400
	(a New Mexico Corporation)
	Tyler at Sixth, Amarillo, Texas 79101
	Telephone (303) 571-7511

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 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 October 31, 2002:


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. 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
EX-4.01 Supplemental Indenture dated Aug. 15, 2002
EX-4.02 Supplemental Indenture dated Sept 15, 2002
EX-4.03 Supplemental Indenture dated Aug. 15, 2002
EX-4.04 Supplemental Indenture dated Sept 15, 2002
EX-4.05 Supplemental Indenture dated June 1, 2002
EX-4.06 Supplemental Indenture dated July 1, 2002
EX-99.01 Statement pursuant to Private Securities
EX-99.02 Certification Pursuant to 18 USC Sec 1350
EX-99.03 Certification Pursuant to 18 USC Sec 1350
EX-99.04 Certification Pursuant to 18 USC Sec 1350
EX-99.05 Certification Pursuant to 18 USC Sec 1350

Table of Contents


PART I — FINANCIAL INFORMATION
Item l. Financial Statements			3
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			27
Item 4. Controls and Procedures			36
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			36
Item 6. Exhibits and Reports on Form 8-K			37

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. Financial Statements

NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(Thousands of Dollars)


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

			2002			2001			2002			2001

Operating revenues:
	Electric utility		$	717,173		$	765,607		$	1,818,973		$	2,034,081
	Gas utility			31,186			51,691			308,504			497,361
	Electric trading margin			(3,059	)		—			(1,917	)		—
	Other			6,836			9,408			18,800			36,552

		Total operating revenues		752,136			826,706			2,144,360			2,567,994
Operating expenses:
	Electric fuel and purchased power			236,033			322,127			613,386			806,986
	Cost of gas sold and transported			21,848			38,309			209,726			392,824
	Other operating and maintenance expenses			190,189			200,243			600,291			622,279
	Depreciation and amortization			89,285			82,536			262,274			249,130
	Taxes (other than income taxes)			45,363			27,800			131,291			129,141
	Special charges (see Note 2)			—			—			4,324			—

		Total operating expenses		582,718			671,015			1,821,292			2,200,360

Operating income				169,418			155,691			323,068			367,634
Other income (expense) — net				3,709			(1,250	)		18,269			2,558
Interest charges and financing costs:
	Interest charges — net of amounts capitalized			30,805			21,199			65,423			65,537
	Distributions on redeemable preferred securities of subsidiary trust			3,938			3,938			11,813			11,813

		Total interest charges and financing costs		34,743			25,137			77,236			77,350

Income before income taxes				138,384			129,304			264,101			292,842
Income taxes				55,392			53,214			105,652			118,179

Net income			$	82,992		$	76,090		$	158,449		$	174,663

See Notes to Consolidated Financial Statements

NSP-MINNESOTA
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(Thousands of Dollars)


				Nine Months Ended Sept. 30

				2002			2001

Operating activities:
	Net income			$	158,449		$	174,663
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			270,556			259,607
		Nuclear fuel amortization			37,208			31,843
		Deferred income taxes			(37,217	)		7,532
		Amortization of investment tax credits			(6,236	)		(6,108	)
		Allowance for equity funds used during construction			(3,843	)		(4,676	)
		Conservation incentive accrual adjustments			(6,564	)		(32,218	)
		Gain on sale of property			(6,785	)		—
		Change in accounts receivable			35,017			71,010
		Change in inventories			(6,345	)		(3,803	)
		Change in other current assets			50,586			63,376
		Change in accounts payable			(54,831	)		(74,001	)
		Change in other current liabilities			34,986			(25,927	)
		Change in other assets and liabilities			(1,604	)		(26,442	)

			Net cash provided by operating activities		463,377			434,856
Investing activities:
	Utility capital/construction expenditures				(280,584	)		(300,169	)
	Proceeds from sale of property				11,152			—
	Allowance for equity funds used during construction				3,843			4,676
	Investments in external decommissioning fund				(47,141	)		(42,559	)
	Other investments — net				(1,599	)		(10,164	)

		Net cash used in investing activities			(314,329	)		(348,216	)
Financing activities:
	Short-term borrowings — net				(281,008	)		(140,804	)
	Proceeds from issuance of long-term debt				624,690			—
	Repayment of long-term debt, including reacquisition premiums				(778	)		(1,073	)
	Capital contributions from parent				42,431			184,934
	Dividends paid to parent				(143,728	)		(123,292	)

		Net cash provided by (used in) financing activities			241,607			(80,235	)
Net increase in cash and cash equivalents					390,655			6,405
Cash and cash equivalents at beginning of year					17,169			11,926

Cash and cash equivalents at end of year				$	407,824		$	18,331

See Notes to Consolidated Financial Statements

NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(Thousands of Dollars)


			Sept. 30,			Dec. 31,
			2002			2001

ASSETS
Current assets:
	Cash and cash equivalents		$	407,824		$	17,169
	Accounts receivable — net of allowance for bad debts: $5,146 and $5,452, respectively			212,640			227,007
	Accounts receivable from affiliates			10,762			31,528
	Accrued unbilled revenues			75,300			125,770
	Materials and supplies inventories at average cost			108,734			103,934
	Fuel inventory at average cost			33,201			31,945
	Gas inventory at average cost			25,411			25,122
	Derivative instruments valuation			1,762			204
	Prepayments and other			45,823			48,285

		Total current assets		921,457			610,964

Property, plant and equipment, at cost:
	Electric utility plant			6,761,235			6,582,337
	Gas utility plant			707,656			695,338
	Construction work in progress			387,414			316,468
	Other			368,184			368,513

		Total property, plant and equipment		8,224,489			7,962,656
	Less accumulated depreciation			(4,557,101	)		(4,310,214	)
	Nuclear fuel — net of accumulated amortization: $1,047,063 and $1,009,855, respectively			53,295			96,315

		Net property, plant and equipment		3,720,683			3,748,757

Other assets:
	Nuclear decommissioning fund investments			604,148			596,113
	Other investments			23,901			22,542
	Regulatory assets			229,433			226,088
	Prepaid pension asset			244,857			188,287
	Other			74,530			64,278

		Total other assets		1,176,869			1,097,308

		Total assets	$	5,819,009		$	5,457,029

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	232,228		$	153,134
	Short-term debt			100,176			381,184
	Accounts payable			181,103			235,930
	Accounts payable to affiliates			42,566			42,550
	Taxes accrued			209,764			168,491
	Dividends payable to parent			51,859			44,332
	Other			62,167			76,004

		Total current liabilities		879,863			1,101,625

Deferred credits and other liabilities:
	Deferred income taxes			678,715			697,605
	Deferred investment tax credits			75,964			82,598
	Regulatory liabilities			482,822			468,051
	Benefit obligations and other			137,357			133,771

		Total deferred credits and other liabilities		1,374,858			1,382,025

Long-term debt				1,578,753			1,039,220
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				804,586			762,155
Retained earnings				997,629			990,435
Leveraged ESOP				(16,680	)		(18,564	)
Accumulated other comprehensive income				(10	)		123

	Total common stockholder’s equity			1,785,535			1,734,159
Commitments and contingencies (See Note 5)
	Total liabilities and equity		$	5,819,009		$	5,457,029

See Notes to Consolidated Financial Statements

NSP-WISCONSIN
STATEMENTS OF INCOME (UNAUDITED)
(Thousands of Dollars)


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

			2002			2001		2002		2001

Operating revenues:
	Electric utility		$	121,578		$	122,897	$	348,689	$	340,732
	Gas utility			8,113			9,089		67,352		96,615
	Other			541			125		652		336

		Total operating revenues		130,232			132,111		416,693		437,683
Operating expenses:
	Electric fuel and purchased power			54,971			65,533		159,617		185,049
	Cost of gas sold and transported			4,201			6,381		46,958		76,325
	Cost of sales — nonregulated and other			388			—		388		—
	Other operating and maintenance expenses			27,785			26,449		76,677		77,513
	Depreciation and amortization			11,313			10,286		33,152		30,807
	Taxes (other than income taxes)			4,012			4,031		12,229		12,065
	Special charges (see Note 2)			—			—		511		—

		Total operating expenses		102,670			112,680		329,532		381,759
Operating income				27,562			19,431		87,161		55,924
Other income (expense) — net				(514	)		366		479		1,101
Interest charges				5,763			5,542		17,336		16,383

Income before income taxes				21,285			14,255		70,304		40,642
Income taxes				8,789			5,628		27,439		15,509

Net income			$	12,496		$	8,627	$	42,865	$	25,133

See Notes to Financial Statements

NSP-WISCONSIN
STATEMENTS OF CASH FLOWS (UNAUDITED)
(Thousands of Dollars)


				Nine Months Ended Sept. 30

				2002			2001

Operating activities:
	Net income			$	42,865		$	25,133
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			34,052			31,577
		Deferred income taxes			2,364			1,903
		Amortization of investment tax credits			(605	)		(614	)
		Allowance for equity funds used during construction			(406	)		(1,111	)
		Undistributed equity in earnings of unconsolidated affiliates			(147	)		(217	)
		Change in accounts receivable			299			15,158
		Change in inventories			256			(1,005	)
		Change in other current assets			13,274			20,736
		Change in accounts payable			13,703			(36,228	)
		Change in other current liabilities			12,897			1,918
		Change in other assets and liabilities			(6,188	)		(6,762	)

			Net cash provided by operating activities		112,364			50,488
Investing activities:
	Capital/construction expenditures				(31,136	)		(45,842	)
	Allowance for equity funds used during construction				406			1,111
	Other investments — net				(75	)		(98	)

			Net cash used in investing activities		(30,805	)		(44,829	)
Financing activities:
	Short-term borrowings from affiliate — net				(34,300	)		(8,700	)
	Capital contributions from parent				2,438			25,000
	Dividends paid to parent				(34,757	)		(21,959	)

			Net cash used in financing activities		(66,619	)		(5,659	)

Net increase in cash and cash equivalents					14,940			—
Cash and cash equivalents at beginning of period					30			31

Cash and cash equivalents at end of period				$	14,970		$	31

See Notes to Financial Statements

NSP-WISCONSIN
BALANCE SHEETS (UNAUDITED)
(Thousands of Dollars)


				Sept. 30,			Dec. 31,
				2002			2001

ASSETS
Current assets:
	Cash and cash equivalents			$	14,970		$	30
	Accounts receivable — net of allowance for bad debts: $1,258 and $969, respectively				34,422			31,870
	Accounts receivable from affiliates				—			3,006
	Accrued unbilled revenues				13,084			20,596
	Materials and supplies inventories at average cost				7,040			5,885
	Fuel inventory at average cost				4,376			5,854
	Gas inventory. at average cost				3,378			3,311
	Prepaid taxes				10,028			13,157
	Prepayments and other				1,316			3,949

		Total current assets			88,614			87,658

Property, plant and equipment, at cost:
	Electric utility plant				1,149,934			1,132,114
	Gas utility plant				129,952			127,635
	Other and construction work in progress				122,431			115,435

			Total property, plant and equipment		1,402,317			1,375,184
	Less accumulated depreciation				(582,649	)		(553,467	)

		Net property, plant and equipment			819,668			821,717

Other assets:
	Other investments				10,046			9,824
	Regulatory assets				44,460			37,123
	Prepaid pension asset				36,058			28,563
	Other				7,757			7,373

			Total other assets		98,321			82,883

			Total assets	$	1,006,603		$	992,258

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt			$	34		$	34
	Short-term debt — notes payable to affiliate				—			34,300
	Accounts payable				13,846			14,482
	Accounts payable to affiliates				14,339			—
	Dividends payable to parent				12,372			10,988
	Other				34,708			22,515

			Total current liabilities		75,299			82,319

Deferred credits and other liabilities:
	Deferred income taxes				123,110			119,895
	Deferred investment tax credits				15,022			15,628
	Regulatory liabilities				16,150			16,891
	Benefit obligations and other				45,194			34,925

			Total deferred credits and other liabilities		199,476			187,339

Long-term debt					313,119			313,054
Common stock — authorized 1,000,000 shares of $100 par value; outstanding 933,000 shares					93,300			93,300
Premium on common stock					62,210			59,771
Retained earnings					263,199			256,475

			Total common stockholder’s equity		418,709			409,546
Commitments and contingent liabilities (see Note 5)

			Total liabilities and equity	$	1,006,603		$	992,258

See Notes to Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(Thousands of Dollars)


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

				2002			2001			2002			2001

Operating revenues:
	Electric utility			$	497,885		$	627,106		$	1,387,414		$	1,826,923
	Electric trading margin				2,276			6,559			(41	)		36,683
	Gas utility				89,430			153,857			521,858			986,391
	Steam and other				4,535			4,354			17,513			23,422

		Total operating revenues			594,126			791,876			1,926,744			2,873,419
Operating expenses:
	Electric fuel and purchased power				232,021			401,224			637,963			1,089,550
	Cost of gas sold and transported				31,836			97,038			293,542			762,422
	Cost of sales — steam and other				3,782			914			7,581			8,526
	Other operating and maintenance expenses				111,801			124,269			334,580			337,512
	Depreciation and amortization				61,480			59,088			190,138			175,369
	Taxes (other than income taxes)				18,489			9,273			61,201			53,151
	Special charges (see Note 2)				1			—			132			23,018

			Total operating expenses		459,410			691,806			1,525,137			2,449,548

Operating income					134,716			100,070			401,607			423,871
Other income (expense) — net					(2,428	)		(2,722	)		(2,540	)		4,519
Interest charges and financing costs:
	Interest charges — net of amount capitalized				34,788			26,976			94,902			86,147
	Distributions on redeemable preferred securities of subsidiary trust				3,686			3,800			11,058			11,400

			Total interest charges and financing costs		38,474			30,776			105,960			97,547

Income before income taxes					93,814			66,572			293,107			330,843
Income taxes					26,847			18,625			97,087			109,205

Net income				$	66,967		$	47,947		$	196,020		$	221,638

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(Thousands of Dollars)


				Nine Months Ended Sept. 30,

				2002			2001

Operating activities:
	Net income			$	196,020		$	221,638
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			196,764			181,566
		Deferred income taxes			26,572			(27,891	)
		Amortization of investment tax credits			(3,211	)		(3,089	)
		Allowance for equity funds used during construction			22			(526	)
		Write-off of post-employment costs			—			23,018
		Unrealized gain on derivative financial instruments			(85,411	)		—
		Change in accounts receivable			45,762			63,580
		Change in inventories			(21,090	)		(22,610	)
		Change in other current assets			32,010			261,549
		Change in accounts payable			(60,217	)		(266,476	)
		Change in other current liabilities			95,254			105,160
		Change in other assets and liabilities			20,700			(17,909	)

			Net cash provided by operating activities		443,175			518,010
Investing activities:
	Capital/construction expenditures				(359,412	)		(299,708	)
	Proceeds from disposition of property, plant and equipment				17,527			5,401
	Allowance for equity funds used during construction				(22	)		526
	Other investments — net				(1,036	)		1,781

			Net cash used in investing activities		(342,943	)		(292,000	)
Financing activities:
	Short-term borrowings — net				(487,388	)		105,075
	Proceeds from issuance of long-term debt				594,000			100,000
	Repayment of long-term debt, including reacquisition premiums				(3,142	)		(241,248	)
	Capital contributions from parent				54,749			—
	Dividends paid to parent				(169,985	)		(166,922	)

			Net cash used in financing activities		(11,766	)		(203,095	)
	Net (decrease) increase in cash and cash equivalents				88,466			22,915
	Cash and cash equivalents at beginning of period				22,666			15,696

	Cash and cash equivalents at end of period			$	111,132		$	38,611

See Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(Thousands of Dollars)


			Sept. 30,			Dec. 31,
			2002			2001

ASSETS
Current assets:
	Cash and cash equivalents		$	111,132		$	22,666
	Accounts receivable — net of allowance for bad debts of $12,731 and $14,510, respectively			140,588			209,913
	Accounts receivable from affiliates			23,563			—
	Accrued unbilled revenues			215,694			269,167
	Recoverable purchased gas and electric energy costs			43,346			16,763
	Materials and supplies inventories at average cost			47,368			40,893
	Fuel inventory at average cost			30,339			22,135
	Gas inventory — replacement cost (below) in excess of LIFO: ($41,165) and $11,331, respectively			85,917			79,505
	Derivative instruments valuation — at market			3,742			3,855
	Prepayments and other			17,018			56,001

		Total current assets		718,707			720,898

Property, plant and equipment, at cost:
	Electric utility			5,328,086			5,253,693
	Gas utility			1,472,638			1,416,730
	Construction work in progress			391,844			273,539
	Other			624,209			586,261

		Total property, plant and equipment		7,816,777			7,530,223
	Less: accumulated depreciation			(2,870,773	)		(2,746,687	)

		Net property, plant and equipment		4,946,004			4,783,536

Other assets:
	Other investments			11,148			10,112
	Regulatory assets			241,201			192,841
	Prepaid pension asset			69,547			60,797
	Other			31,235			72,694

		Total other assets		353,131			336,444

		Total assets	$	6,017,842		$	5,840,878

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	267,089		$	17,174
	Short-term debt			88,074			562,812
	Note payable to affiliate			15,915			28,565
	Accounts payable			298,069			359,406
	Accounts payable to affiliates			61,271			60,151
	Taxes accrued			93,494			60,780
	Dividends payable to parent			60,925			53,387
	Derivative instruments valuation — at market			3,421			50,385
	Other			203,786			141,245

		Total current liabilities		1,092,044			1,333,905

Deferred credits and other liabilities:
	Deferred income taxes			555,163			564,268
	Deferred investment tax credits			76,441			79,652
	Regulatory liabilities			46,589			49,048
	Other deferred credits			2,575			12,435
	Customer advances for construction			93,932			85,582
	Benefit obligations and other			76,623			66,835

		Total deferred credits and other liabilities		851,323			857,820

Long-term debt				1,812,500			1,465,055
Mandatorily redeemable preferred securities of subsidiary trust				194,000			194,000
Common stock — authorized 100 shares of $0.01 par value, outstanding 100 shares				—			—
Premium on common stock				1,644,833			1,590,084
Retained earnings				422,843			404,347
Accumulated other comprehensive income				299			(4,333	)

		Total common stockholder’s equity		2,067,975			1,990,098
Commitments and contingent liabilities (see Note 5)

		Total liabilities and equity	$	6,017,842		$	5,840,878

See Notes to Consolidated Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF INCOME (UNAUDITED)
(Thousands of Dollars)


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

			2002		2001		2002		2001

Operating revenues — electric utility			$	291,857	$	387,219	$	770,466	$	1,088,173
Operating expenses:
	Electric fuel and purchased power			158,324		226,687		414,699		679,005
	Other operating and maintenance expenses			34,774		43,548		112,867		129,218
	Depreciation and amortization			22,487		20,697		65,778		61,506
	Taxes (other than income taxes)			13,884		10,608		39,861		35,684
	Special charges (see Note 2)			—		—		5,114		—

		Total operating expenses		229,469		301,540		638,319		905,413

Operating income				62,388		85,679		132,147		182,760
Other income — net				2,075		1,965		4,174		8,255
Interest charges and financing costs:
	Interest charges — net of amounts capitalized			11,570		9,319		34,404		34,207
	Distributions on redeemable preferred securities of subsidiary trust			1,963		1,963		5,888		5,888

		Total interest charges and financing costs		13,533		11,282		40,292		40,095

Income before income taxes				50,930		76,362		96,029		150,920
Income taxes				19,189		28,653		36,111		56,860

Net income			$	31,741	$	47,709	$	59,918	$	94,060

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF CASH FLOWS (UNAUDITED)
(Thousands of Dollars)


				Nine Months Ended Sept. 30,

				2002			2001

Operating activities:
	Net income			$	59,918		$	94,060
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			72,129			64,301
		Deferred income taxes			14,743			(19,144	)
		Amortization of investment tax credits			(187	)		(188	)
		Change in accounts receivable			(10,764	)		(5,568	)
		Change in inventories			(4,978	)		(632	)
		Change in other current assets			28,969			74,475
		Change in accounts payable			4,527			(50,427	)
		Change in other current liabilities			(31,482	)		27,418
		Change in other assets and liabilities			(14,938	)		(14,860	)

			Net cash provided by operating activities		117,937			169,435
Investing activities:
	Capital/construction expenditures				(38,198	)		(93,445	)
	Costs/proceeds from disposition of property, plant and equipment				4,059			—
	Other investments — net				(3,003	)		119,942

			Net cash (used in) provided by investing activities		(37,142	)		26,497
Financing activities:
	Short-term borrowings — net				—			(135,173	)
	Repayment of long-term debt, including reacquisition premiums				—			168
	Capital contributions from parent				615			—
	Dividends paid to parent				(68,912	)		(64,566	)

			Net cash used in financing activities		(68,297	)		(199,571	)
	Net (decrease) increase in cash and cash equivalents				12,498			(3,639	)
	Cash and cash equivalents at beginning of period				65,499			10,826

	Cash and cash equivalents at end of period			$	77,997		$	7,187

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.
BALANCE SHEETS (UNAUDITED)
(Thousands of Dollars)


			Sept. 30,			Dec. 31,
			2002			2001

ASSETS
Current assets:
	Cash and cash equivalents		$	77,997		$	65,499
	Accounts receivable — net of allowance for bad debts of $1,162 and $1,785, respectively			53,366			61,688
	Accounts receivable from affiliates			19,086			—
	Accrued unbilled revenues			51,886			75,924
	Materials and supplies inventories at average cost			17,611			12,588
	Fuel and gas inventories at average cost			1,345			1,390
	Current portion of accumulated deferred income taxes			—			10,068
	Derivative instruments valuation — at market			562			—
	Prepayments and other			5,240			10,170

		Total current assets		227,093			237,327

Property, plant and equipment, at cost:
	Electric utility			3,060,002			3,056,459
	Other and construction work in progress			81,583			55,436

		Total property, plant and equipment		3,141,585			3,111,895
	Less: accumulated depreciation			(1,334,529	)		(1,275,501	)

		Net property, plant and equipment		1,807,056			1,836,394

Other assets:
	Other investments			14,348			11,345
	Regulatory assets			105,989			96,613
	Prepaid pension asset			99,078			82,503
	Deferred charges and other			17,696			36,598

		Total other assets		237,111			227,059

		Total assets	$	2,271,260		$	2,300,780

LIABILITIES AND EQUITY
Current liabilities:
	Accounts payable		$	67,222		$	72,204
	Accounts payable to affiliates			11,400			1,891
	Taxes accrued			40,347			35,274
	Interest accrued			11,012			9,696
	Dividends payable to parent			24,469			20,969
	Current portion of accumulated deferred income taxes			7,004			—
	Derivative instruments valuation — at market			1,177			1,131
	Other			23,229			68,105

		Total current liabilities		185,860			209,270

Deferred credits and other liabilities:
	Deferred income taxes			393,781			392,907
	Deferred investment tax credits			4,280			4,467
	Regulatory liabilities			2,399			1,117
	Derivative instruments valuation — at market			6,135			5,809
	Benefit obligations and other			18,925			15,815

		Total deferred credits and other liabilities		425,520			420,115

Long-term debt				725,591			725,375
Mandatorily redeemable preferred securities of subsidiary trust				100,000			100,000
Common stock — authorized 200 shares of $1.00 par value, outstanding 100 shares				—			—
Premium on common stock				406,151			405,536
Retained earnings				432,423			444,917
Accumulated other comprehensive loss				(4,285	)		(4,433	)

		Total common stockholder’s equity		834,289			846,020
Commitments and contingent liabilities (see Note 5)

		Total liabilities and equity	$	2,271,260		$	2,300,780

See Notes to 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, 2002, and Dec. 31, 2001, the results of their operations for the three and nine months ended Sept. 30, 2002 and 2001, and their cash flows for the nine months ended Sept. 30, 2002 and 2001. Due to the seasonality of electric and gas sales of Xcel Energy’s Utility Subsidiaries, quarterly 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, 2001. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K’s.

Certain items in the 2001 income statement have been reclassified from amounts previously reported to conform to the 2002 presentation. These reclassifications had no effect on stockholders’ equity or net income as previously reported. The reclassifications were primarily to conform the presentation of all consolidated Xcel Energy subsidiaries to a standard corporate presentation.

1. Accounting Policies and Changes (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Intangible Assets — During the first quarter of 2002, the Utility Subsidiaries of Xcel Energy adopted Statement of Financial Accounting Standard (SFAS) No. 142 — “Goodwill and Other Intangible Assets” (SFAS No. 142), which requires new accounting for intangible assets, including goodwill. Intangible assets with finite lives are being amortized over their economic useful lives and periodically reviewed for impairment.

The Utility Subsidiaries of Xcel Energy have no intangible assets with indefinite lives, and no goodwill. In addition, NSP-Wisconsin, PSCo and SPS have no intangible assets with finite lives.

With respect to NSP-Minnesota’s intangible assets that will continue to be amortized, aggregate amortization expense recognized in the nine months ended Sept. 30, 2002 was approximately $180,000. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $240,000. NSP-Minnesota’s intangible assets subject to amortization at Sept. 30, 2002, consisting primarily of deferred employment agreement costs, were as follows:


	Sept. 30, 2002				Dec. 31, 2001

	Gross Carrying		Accumulated		Gross Carrying		Accumulated
(Millions of dollars)	Amount		Amortization		Amount		Amortization

NSP-Minnesota	$	4.9	$	0.5	$	4.9	$	0.3

Asset Valuation — On Jan. 1, 2002, the Utility Subsidiaries adopted SFAS No. 144 — “Accounting for the Impairment or Disposal of Long-Lived Assets,” which supercedes previous guidance for measurement of asset impairments. The Utility Subsidiaries did not recognize any asset impairments as a result of the adoption

Trading Operations — In June 2002, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) reached a partial consensus on Issue No. 02-3 “Recognition and Reporting Gains and Losses on Energy Trading Contracts under EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF No. 02-3). The EITF concluded that all gains and losses related to energy trading activities within the scope of EITF No. 98-10 (whether or not settled physically) must be shown net in the statement of income, effective for periods ending after July 15, 2002. Xcel Energy has reclassified revenues from trading activities for all comparable prior periods reported. Such energy trading activities recorded as a component of Electric and Gas Trading Costs which have been reclassified to offset Electric and Gas Trading Revenues to present Electric and Gas Trading Margin on a net basis were as indicated in the table below. These reclassifications had no impact on trading margins or reported net income.


	Quarter ended Sept. 30				Nine months ended Sept. 30

(Millions of dollars)	2002		2001		2002		2001

NSP-Minnesota	$	9	$	—	$	26	$	—
PSCo		534		309		1,327		999

On Oct. 25, 2002, the EITF rescinded EITF No. 98-10. With the rescission of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 — “Accounting for Derivative Instruments and

Hedging Activities” (SFAS No. 133) must be accounted for as executory contracts. Contracts previously fair-valued under EITF No. 98-10 that are not also derivatives under SFAS No. 133 must be restated to historical cost through a cumulative effect adjustment. Xcel Energy’s Utility Subsidiaries has not yet evaluated the effect of adopting this decision when required in 2003.

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

Regulatory Recovery Adjustment — In late 2001, SPS filed an application requesting recovery of costs incurred to comply with transition to retail competition legislation in Texas and New Mexico. During the first quarter of 2002, SPS entered into a settlement agreement with intervenors regarding the recovery of restructuring costs in Texas, subject to approval by the state regulatory commission. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million.

2002 Restaffing — During the fourth quarter of 2001, Xcel Energy expensed pretax special charges of $39 million for expected staff consolidation costs for an estimated 500 employees in several utility operating and corporate support areas of Xcel Energy. Approximately $36 million of these restaffing costs were allocated to Xcel Energy’s Utility Subsidiaries consistent with service company cost allocation methodologies utilized under the requirements of the PUHCA. In the first quarter of 2002, the identification of affected employees was completed and additional pretax special charges of $9 million were expensed for the final costs of staff consolidations. Approximately $5 million of these restaffing costs were allocated to Xcel Energy’s Utility Subsidiaries. All 564 of accrued staff terminations have occurred.

The following table summarizes the activity related to accrued special charges (reported in other current liabilities) for the first nine months of 2002.


			Accrued
	Dec. 31, 2001		Special					Sept. 30, 2002
(Millions of dollars)	Liability		Charges		Payments			Liability

Utility and corporate employee severance	$	37	$	9	$	(31	)	$	15
Special charge activities for Utility Subsidiaries:
NSP-Minnesota	$	5	$	4	$	(6	)	$	3
NSP-Wisconsin		2		1		(3	)		—
PSCo.		2		—		(2	)		—
SPS		1		—		(1	)		—

Postemployment Benefits — PSCo’s earnings for the second quarter of 2001 were reduced due to a Colorado Supreme Court decision that resulted in a 2001 pretax write-off of $23 million of regulatory assets related to deferred postemployment benefit costs at PSCo.

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

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

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

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

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

Colorado

Merger Agreements — Under the Stipulation and Agreement approved by the Colorado Public Utilities Commission (CPUC) in connection with the Xcel Energy merger, PSCo agreed to: 1) file a combined electric, gas and steam rate case in 2002 with new rates effective in January 2003, 2) extend its incentive cost adjustment (ICA) mechanism through Dec. 31, 2002 with an increase in the ICA base rate from $12.78 per megawatt hour to a rate based on the 2001 actual costs, 3) continue the Performance Based Regulatory Plan and the Quality Service Plan through 2006 with an electric department earnings cap of 10.5 percent return on equity for 2002, 4) reduce electric rates annually by $11 million for the period August 2000 to July 2002 and 5) cap merger costs associated with electric operations at $30 million and amortize such costs through 2002.

Incentive Cost Adjustment - In early 2002, PSCo filed to increase rates under the ICA to recover the undercollection of electric supply costs through the period ended Dec. 31, 2001 (approximately $14.5 million, which went into effect on June 1, 2002) and to increase the ICA base rate for the recovery of 2002 costs which are projected to be substantially higher than the $12.78 per megawatt hour currently being recovered. PSCo’s actual ICA base costs for 2001 were approximately $19 per megawatt hour. PSCo proposed to increase the ICA base in 2002 to avoid the significant deferral of costs and a large rate increase in 2003, although the Stipulation and Agreement provided for a rate recovery period of April 1, 2003, to March 31, 2004.

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

General Rate Case - In May 2002, Xcel Energy filed a combined general rate case with the CPUC to address increased costs for providing energy to Colorado customers. The net impact of the filings would increase electric revenue by approximately $220 million annually. This is based on $113 million for fuel and purchased power and $107 million for cost of electric service. In addition, PSCo also requested a decrease in natural gas revenue by approximately $13 million to reflect lower wholesale gas costs. PSCo also requested that its authorized rate of return on equity be set at 12 percent for electricity and 12.25 percent for natural gas.

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

• November 2002 — intervenor testimony;

• January 2003 — company rebuttal testimony;

• February/March 2003 — hearings; and

• April/May 2003 — rates effective.

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

Texas

Transition to Competition Cost Recovery Application — In December 2001, SPS filed an application with the Public Utility Commission of Texas (PUCT) to recover $20.3 million in costs related to transition to retail competition from the Texas retail customers. These costs were incurred to position SPS for retail competition, which was eventually delayed for SPS. The filing was amended in March 2002 to reduce the recoverable costs by $7.3 million, which were associated with over-earnings for the calendar year 1999. The PUCT approved SPS using the 1999 over-earnings to offset the claims for reimbursement of transition to competition costs. This reduced the requested net collection in Texas to $13.0 million. In April 2002, a unanimous settlement agreement was reached. Final approval by the PUCT was received in May 2002. The stipulation provides for the recovery of $5.9 million through an incremental cost recovery rider and the capitalization of $1.9 million for metering equipment. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million in the first quarter of 2002. Recovery of the $5.9 million began in July 2002.

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

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

Minnesota

Metro Emissions Reduction Program - In July 2002, NSP-Minnesota filed for approval by the MPUC, a proposal to invest in existing NSP-Minnesota generation facilities to reduce emissions under the terms of legislation adopted by the 2001 Minnesota Legislature. The proposal includes the installation of state-of-the-art pollution control equipment at the A. S. King plant and conversion from coal to natural gas at the High Bridge and Riverside plants. Under the proposal, major construction would start in 2005 and be completed in 2009. Under the terms of the statute, the filing concurrently seeks approval of a rate recovery mechanism for the costs of the proposal, estimated to be a total of $1.1 billion. The rate recovery would be through an annual automatic adjustment mechanism authorized by 2001 legislation, outside a general rate case, and is proposed to be effective at the expiration of the NSP-Minnesota merger rate freeze, which extends through 2005 unless certain exemptions are triggered. The rate recovery proposed by NSP-Minnesota would allow recovery of financing costs of capital expenditures prior to the in-service date of each plant. The proposal is pending comments by interested parties. Other regulatory approvals, such as environmental permitting, are needed before the proposal can be implemented.

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

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

Wisconsin

Retail Electric Fuel Rates — In August 2002, NSP-Wisconsin filed an application with the Public Service Commission of Wisconsin (PSCW), requesting a decrease in Wisconsin retail electric rates for fuel costs. The amount of the proposed rate decrease is approximately $6.3 million on an annual basis. The reasons for the decrease include moderate weather, lower than forecast market power costs, and optimal plant availability. On Aug. 7, 2002, the PSCW issued an order approving the fuel rate credit. The rate credit went into effect on Aug. 12, 2002.

On Oct. 9, 2002, NSP-Wisconsin filed an application with the PSCW requesting another decrease in Wisconsin retail electric rates for fuel costs. The incremental amount of the second proposed rate decrease was approximately $5 million on an annual basis. The reasons for the additional decrease include continued moderate weather; lower than forecast market power costs, and optimal plant availability. On Oct. 16, 2002, the PSCW issued an order approving the revised fuel rate credit, effective Oct. 19, 2002.

Michigan Transfer Pricing- On Oct. 3, 2002, the Michigan Public Service Commission denied NSP-Wisconsin’s request for a waiver of the section of the Michigan Electric Code of Conduct (Michigan Code) dealing with transfer pricing policy. The Michigan Code requires the price of goods and services provided by an affiliate to NSP-Wisconsin be at the lower of market price or cost plus 10 percent, and the price of goods and services provided by NSP-Wisconsin to an affiliate be at the higher of cost or market price. NSP-Wisconsin requested the waiver based on its belief that the Michigan Code conflicts with SEC requirements to price goods and services provided between affiliates at cost. In November 2002, NSP-Wisconsin filed a request for reconsideration of the Oct. 3, 2002 order.

Federal Energy Regulatory Commission

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

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

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

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

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

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

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

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

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

Securities and Exchange Commission/Commodity Futures Trading Commission

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

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

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 believe they 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 13 and 14 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, 2001, 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 and are incorporated herein by reference. Following are unresolved contingencies, which are material to the financial position of Xcel Energy’s Utility Subsidiaries:

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

Environmental Contingencies

PSCo Notice of Violation — On Nov. 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the Clean Air Act’s New Source Review (NSR) requirements related to alleged modifications of electric generating stations located in the South and Midwest. Subsequently, the United States Environmental Protection Agency (EPA) also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including Xcel Energy, seeking to determine whether these utilities engaged in activities that may

have been in violation of the NSR requirements. In 2001, Xcel Energy responded to EPA’s initial information requests related to PSCo plants in Colorado.

On July 1, 2002, PSCo received a Notice of Violation (NOV) from the United States Environmental Protection Agency (EPA) alleging violations of the New Source Review (NSR) requirements of the Clean Air Act at the Comanche and Pawnee Stations in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. PSCo believes it acted in full compliance with the Clean Air Act and NSR process. It believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo also believes that the projects would be expressly authorized under the EPA’s NSR policy announced by the EPA administrator on June 22, 2002. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position.

If the EPA is successful in any subsequent litigation regarding the issues set forth in the NOV or any matter arising as a result of its information requests, it could require PSCo to install additional emission control equipment at the facilities and pay civil penalties. Civil penalties are limited to not more than $25,000 to $27,500 per day for each violation. The ultimate financial impact to PSCo is not determinable at this time.

NSP-Minnesota NSR Information Request — As stated previously, on Nov. 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the NSR requirements related to alleged modifications of electric generating stations located in the South and Midwest. Subsequently, the EPA also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including Xcel Energy, seeking to determine whether these utilities engaged in activities that may have been in violation of the NSR requirements. In 2001, Xcel Energy responded to EPA’s initial information requests related to NSP-Minnesota plants in Minnesota. On May 22, 2002, EPA issued a follow-up information request to Xcel Energy seeking additional information regarding NSR compliance at its plants in Minnesota. Xcel Energy is in the process of responding to the follow-up request.

NSP-Wisconsin Ashland Manufactured Gas Plant Site — NSP-Wisconsin was named as one of three potentially responsible parties (PRP) for creosote and coal tar contamination at a site in Ashland, Wis. The Ashland site includes property owned by NSP-Wisconsin and two other properties: an adjacent city lakeshore park area and a small area of Lake Superior’s Chequemegon Bay adjoining the park.

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

On Sept. 5, 2002, the Ashland site was placed on the National Priorities List (NPL). The NPL is intended primarily to guide the EPA in determining which sites require further investigation. Resolution of Ashland remediation issues is not expected until 2003 or 2004.

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

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

On Aug. 15, 2001, NSP-Wisconsin received a Certificate of Authority to install control equipment necessary to bring the French Island plant into compliance with the large combustor regulations. NSP-Wisconsin began construction of the new air quality equipment on Oct. 1, 2001. NSP-Wisconsin has reached an agreement in principle with La Crosse County through which La Crosse County will pay for the extra emissions equipment required to comply with the EPA regulation. Installation of the control equipment has been completed and source tests on one unit confirm that the unit is now in compliance with the state and federal dioxin standards. NSP-Wisconsin will test the remaining unit during the fourth quarter of 2002.

Legal Contingencies

California Litigation — Public Utility District No. 1 of Snohomish County, Washington, has filed a suit against Xcel Energy in the United States District Court for the Central District of California contending that various of its trading strategies, as reported to the FERC in response to that agency’s investigation of trading strategies discussed above, violated the California Business and Professions Code. Public Utility District No. 1 of Snohomish County contends that the effect of those strategies was to increase amounts that it paid for wholesale power in the spot market in the Pacific Northwest. Xcel Energy and other defendants intend to request the case be dismissed in its entirety. A hearing on the motion to dismiss is scheduled for Dec. 19, 2002.

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

6. Short-Term Borrowings and Financing Activities (NSP-Minnesota and PSCo)

NSP-Minnesota

At Sept. 30, 2002, NSP-Minnesota had approximately $100 million of short-term debt outstanding at a weighted average interest rate of 4.75 percent.

In July 2002, NSP-Minnesota issued $185 million of unsecured bonds. The bonds have a fixed interest rate of 8 percent and mature in 2042.

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

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

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

PSCo

At Sept. 30, 2002, PSCo had approximately $88 million of short-term debt outstanding at a weighted average interest rate of 2.82 percent.

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

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

7. Derivative Valuation and Financial Impacts (NSP-Minnesota, PSCo and SPS)

Xcel Energy’s Utility Subsidiaries analyzes derivative financial instruments in accordance with SFAS No. 133. This statement requires that all derivative financial instruments be recorded on the balance sheet at fair value unless exempted. Changes in a derivative instrument’s fair value must be recognized currently in earnings unless the derivative

has been designated in a qualifying hedging relationship. The application of hedge accounting allows a derivative instrument’s gains and losses to offset related results of the hedged item in the income statement, to the extent effective. SFAS No. 133 requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

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


	Nine months ended Sept. 30, 2002

	NSP-
(Millions of dollars)	Minnesota			PSCo			SPS

Accumulated other comprehensive income (loss) related to SFAS No. 133 — Jan 1, 2002	$	0.1		$	(4.3	)	$	(4.4	)
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges		—			(5.1	)		0.4
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(0.1	)		9.7			(0.3	)

Accumulated other comprehensive income (loss) related to SFAS No. 133 — Sept 30, 2002	$	—		$	0.3		$	(4.3	)


	Nine months ended Sept. 30, 2001

	NSP-
(Millions of dollars)	Minnesota		PSCo			SPS

Net unrealized transition gain (loss) at adoption, 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
Accumulated other comprehensive income (loss) related to SFAS

No. 133 — Sept. 30, 2001	$	—	$	0.8		$	(4.4	)

PSCo recorded pretax losses in Electric Fuel and Purchased Power of $0.6 million and $1.2 million for the three months ended Sept. 30, 2002 and 2001, respectively, due to the effects of SFAS No. 133. PSCo recorded pretax gains in Electric Fuel and Purchased Power expense of $0.4 million and pretax losses of $1.0 million for the nine months ended Sept. 30, 2002 and 2001, respectively, due to the effects of SFAS No. 133. During these periods, there was no impact on earnings related to SFAS No. 133 for NSP-Minnesota and SPS.

Normal Purchases or Normal Sales

Xcel Energy’s Utility Subsidiaries enter into fixed price contracts for the purchase and sale of various commodities for use in their business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that meet the requirements of normal are documented as normal and exempted from the accounting and reporting requirements of SFAS No. 133.

Xcel Energy’s Utility Subsidiaries evaluate all of their contracts when such contracts are entered into to determine if they are derivatives and, if so, if they qualify and meet the normal designation requirements under SFAS No. 133. None of the contracts entered into within the trading operations are considered normal under the provisions of SFAS No. 133.

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

Cash Flow Hedges

NSP-Minnesota, PSCo and SPS enter into derivative instruments to manage their respective exposure to changes in commodity prices. These derivative instruments take the form of fixed price, floating price or index sales or purchases

and options, such as puts, calls and swaps. These derivative instruments are designated as cash flow hedges for accounting purposes and the changes in the fair value of these instruments are recorded as a component of Other Comprehensive Income. At Sept. 30, 2002, NSP-Minnesota, PSCo and SPS had various commodity related contracts through the next 12 months. Earnings on these cash flow hedges are recorded as the hedged purchase or sales transaction is completed. This could include the physical sale of electric energy or the usage of natural gas to generate electric energy. As of Sept. 30, 2002, PSCo and SPS expect to reclassify into earnings through September 2003 net gains from Other Comprehensive Income of approximately $0.3 million and $0.4 million, respectively. NSP-Minnesota does not expect to reclassify any gains (losses) into earnings through September 2003.

As required by SFAS No. 133, PSCo recorded losses of $0.6 million related to ineffectiveness on commodity cash flow hedges during the three months ended Sept. 30, 2002. There were no gains (losses) recorded during the three months ended Sept. 30, 2001. PSCo recorded gains of $0.4 million and losses of $1.0 million related to ineffectiveness on commodity cash flow hedges during the nine months ended Sept. 30, 2002 and 2001, respectively. PSCo recorded losses of $1.2 million for the three months ended Sept. 30, 2001 related to derivative financial instruments excluded from the assessment of effectiveness. There were no gains (losses) recorded during the nine months ended Sept. 30, 2001. In 2001, an immaterial amount related to cash flow hedges that were discontinued because the hedged transactions were no longer probable.

SPS enters into interest rate swap instruments that effectively fix the interest payments on certain floating rate debt obligations. These derivative instruments are designated as cash flow hedges for accounting purposes and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. SPS expects to reclassify into earnings through September 2003 net losses from Other Comprehensive Income of approximately $0.8 million.

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

Derivatives Not Qualifying for Hedge Accounting

NSP-Minnesota and PSCo have trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market basis in their respective Consolidated Statements of Income. All financial derivative instruments are recorded at the amount of the gain or loss from the transaction within Operating Revenues on the Consolidated Statements of Income.

8. Pension Plan Funding and Costs (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

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

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

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

9. 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 (net of trading costs) are included in the Electric Utility segment.

(Thousands of dollars)

NSP-Minnesota


		Electric		Gas			All			Consolidated
		Utility		Utility			Other			Total

Three months ended Sept. 30, 2002
Revenues from:
External customers		$	713,946	$	31,184		$	6,836		$	751,966
Internal customers			168		2			—			170

	Total revenue		714,114		31,186			6,836			752,136
Segment net income		$	79,906	$	(5,181	)	$	8,267		$	82,992
Sept. 30, 2001
Revenues from:
External customers		$	765,421	$	51,689		$	9,408		$	826,518
Internal customers			186		2			—			188

	Total revenue		765,607		51,691			9,408			826,706
Segment net income (loss)		$	80,381	$	(4,201	)	$	(90	)	$	76,090


		Electric		Gas		All			Consolidated
		Utility		Utility		Other			Total

Nine months ended Sept. 30, 2002

Revenues from:
External customers		$	1,816,593	$	308,473	$	18,800		$	2,143,866
Internal customers			463		31		—			494

	Total revenue		1,817,056		308,504		18,800			2,144,360
Segment net income		$	146,606	$	3,041	$	8,802		$	158,449

Sept. 30, 2001

Revenues from:
External customers		$	2,033,549	$	497,215	$	36,552		$	2,567,316
Internal customers			532		146		—			678

	Total revenue		2,034,081		497,361		36,552			2,567,994
Segment net income (loss)		$	161,171	$	13,833	$	(341	)	$	174,663

NSP-Wisconsin


		Electric		Gas			All		Consolidated
		Utility		Utility			Other		Total

Three months ended Sept. 30, 2002

Revenues from:
External customers		$	121,539	$	8,213		$	541	$	130,293
Internal customers			39		(100	)		—		(61	)

	Total revenue		121,578		8,113			541		130,232
Segment net income		$	11,589	$	865		$	42	$	12,496

Sept. 30, 2001

Revenues from:
External customers		$	122,862	$	8,566		$	125	$	131,553
Internal customers			35		523			—		558

	Total revenue		122,897		9,089			125		132,111
Segment net income (loss)		$	10,643	$	(2,016	)	$	—	$	8,627

Nine months ended Sept. 30, 2002

Revenues from:
External customers		$	348,564	$	66,752		$	652	$	415,968
Internal customers			125		600			—		725

	Total revenue		348,689		67,352			652		416,693
Segment net income		$	36,916	$	5,873		$	76	$	42,865

Sept. 30, 2001

Revenues from:
External customers		$	340,604	$	95,200		$	336	$	436,140
Internal customers			128		1,415			—		1,543

	Total revenue		340,732		96,615			336		437,683
Segment net income		$	22,172	$	2,961		$	—	$	25,133

PSCo


		Electric		Gas		All		Consolidated
		Utility		Utility		Other		Total

Three months ended Sept. 30, 2002

Revenues from:
External customers		$	500,087	$	89,425	$	4,535	$	594,047
Internal customers			74		5		—		79

	Total revenue		500,161		89,430		4,535		594,126
Segment net income		$	48,644	$	10,401	$	7,922	$	66,967

Sept. 30, 2001

Revenues from:
External customers		$	633,634	$	153,300	$	4,354	$	791,288
Internal customers			31		557		—		588

	Total revenue		633,665		153,857		4,354		791,876
Segment net income		$	51,951	$	5,868	$	9,148	$	47,947


Nine months ended		Electric		Gas		All		Consolidated
Sept. 30, 2002		Utility		Utility		Other		Total

Revenues from:
External customers		$	1,387,179	$	521,826	$	17,513	$	1,926,518
Internal customers			194		32		—		226

	Total revenue		1,387,373		521,858		17,513		1,926,744
Segment net income		$	140,208	$	37,176	$	18,636	$	196,020

Sept. 30, 2001

Revenues from:
External customers		$	1,863,509	$	984,711	$	23,422	$	2,871,642
Internal customers			97		1,680		—		1,777

	Total revenue		1,863,606		986,391		23,422		2,873,419
Segment net income		$	171,835	$	27,503	$	22,300	$	221,638

SPS

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 $291.9 million and $387.2 million for the three months ended Sept. 30, 2002 and 2001, respectively. Revenues from external customers were $770.5 million and $1,088.2 million for the nine months ended Sept. 30, 2002 and 2001, respectively.

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

NSP-Minnesota

The components of total comprehensive income are shown below:


		Three months ended					Nine months ended
(Thousands of dollars)		Sept. 30,					Sept. 30,

		2002			2001		2002			2001

Net income		$	82,992		$	76,090	$	158,449		$	174,663
Other comprehensive loss:
	After-tax net unrealized losses on derivatives accounted for as hedges (see Note 7)		(575	)		—		—			—
	After-tax net realized losses (gains) on derivative transactions reclassified into earnings (see Note 7)		217			—		(120	)		—
	Unrealized loss on marketable securities		(6	)		—		(11	)		—

Other comprehensive loss			(364	)		—		(131	)		—

Comprehensive income		$	82,628		$	76,090	$	158,318		$	174,663

The accumulated comprehensive income in stockholder’s equity at Sept. 30, 2002, relates to valuation adjustments on derivative financial instruments and hedging activities and the mark-to-market components of our marketable securities.

NSP-Wisconsin

For NSP-Wisconsin, comprehensive income equals net income for the quarter and nine months ended Sept. 30, 2002 and 2001.

PSCo

The components of total comprehensive income are shown below:


		Three months ended						Nine months ended
(Thousands of dollars)		Sept. 30,						Sept. 30,

		2002			2001			2002			2001

Net income		$	66,967		$	47,947		$	196,020		$	221,638
Other comprehensive income: Cumulative effect of accounting change-net unrealized transition gain upon adoption of SFAS No. 133			—			—			—			1,649
	After-tax net unrealized losses on derivatives accounted for as hedges (see Note 7)		(14,157	)		(9,504	)		(5,139	)		(26,998	)
	After-tax net realized losses on derivative transactions reclassified into earnings (see Note 7)		14,766			10,429			9,771			26,176

Other comprehensive income			609			925			4,632			827

Comprehensive income		$	67,576		$	48,872		$	200,652		$	222,465

The accumulated comprehensive income in stockholder’s equity at Sept. 30, 2002 and 2001, relates to valuation adjustments on derivative financial instruments and hedging activities and the mark-to-market component of our marketable securities.

SPS

The components of total comprehensive income are shown below:


		Three months ended					Nine months ended
(Thousands of dollars)		Sept. 30					Sept. 30

		2002			2001		2002			2001

Net income		$	31,741		$	47,709	$	59,918		$	94,060
Other comprehensive (loss) income: Cumulative effect of accounting change-net unrealized transition loss upon adoption of SFAS No. 133			—			—		—			(2,626	)
	After-tax net unrealized (losses) gains on derivatives accounted for as hedges (see Note 7)		(435	)		184		450			(2,239	)
	After-tax net realized (gains) losses on derivative transactions reclassified into earnings (see Note 7)		(422	)		162		(303	)		406

Other comprehensive (loss) income			(857	)		346		147			(4,459	)

Comprehensive income		$	30,884		$	48,055	$	60,065		$	89,601

The accumulated comprehensive loss in stockholder’s equity at Sept. 30, 2002 and 2001, relates to valuation adjustments on derivative financial instruments and hedging activities.

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

Except for the supplemental discussion of NRG credit impacts provided below, 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 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 and federal 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 and other western 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, 2002.

Market Risks

The Utility Subsidiaries of Xcel Energy are exposed to market risks, including changes in commodity prices and interest rates as disclosed in Management’s Discussion and Analysis in their annual reports on Form 10-K for the year ended Dec. 31, 2001. Commodity price and interest rate risks for the Utility Subsidiaries of Xcel Energy are mitigated in most jurisdictions due to cost-based rate regulation.

The energy market continues to evolve and change as market conditions and participants vary. Xcel Energy and its Utility Subsidiaries have responded to the change to the energy trading market environment and believe there has been no material change in its market risk exposures.

Pending Accounting Changes

SFAS No. 143 — In 2001, the Financial Accounting Standards Board issued 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 at the end of the asset’s life the recorded liability differs from the actual obligations paid, SFAS No. 143 requires that a gain or loss be recognized at that time. However, rate-regulated entities may recognize a regulatory asset or liability instead, if the criteria for such treatment are met.

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, 2001, NSP-Minnesota recorded and recovered in rates $623 million of decommissioning obligations and had estimated discounted decommissioning cost obligations to be $878 million as of that date.

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

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

Xcel Energy expects to adopt SFAS 143 as required on Jan. 1, 2003.

SFAS No. 145 — In April 2002, the FASB issued SFAS No. 145 — “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” that supercedes previous guidance for the reporting of gains and losses from extinguishment of debt and accounting for leases, among other things. The impact of SFAS No. 145 is not expected to be material to any of the Utility Subsidiaries of Xcel Energy.

SFAS No. 146 — In July 2002, the FASB issued SFAS No. 146 — “Accounting for Exit or Disposal Activities,” addressing recognition, measurement and reporting of costs associated with exit and disposal activities, including restructuring activities. The impact of SFAS No. 146 is not expected to be material to any of the Utility Subsidiaries of Xcel Energy.

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

NRG Credit Impacts on Liquidity and Capital Resources of Utility Subsidiaries

Capital Sources — Short-Term Funding Sources — Since the fourth quarter of 2001, various rating agencies have downgraded credit ratings for Xcel Energy and its subsidiaries, including NRG Energy Inc. (NRG). While NRG’s liquidity and capital requirements have been the focus of the agencies’ concerns, there have been secondary impacts on the credit ratings and capital market access of Xcel Energy’s Utility Subsidiaries. These have not been passed on to ratepayers.

Short-term borrowings as a source of short-term funding is affected by access to reasonably priced capital markets. This access is dependent in part on credit agency reviews. In the past year, credit ratings for Xcel Energy’s Utility Subsidiaries have been adversely affected by NRG’s credit contingencies, despite what management believes is a reasonable separation of NRG’s operations and credit risk from Xcel Energy’s utility operations and financing activities. As of Sept. 30, 2002, the following represents the credit ratings assigned to the Utility Subsidiaries:


Company	Credit Type	Moody's *	Standard & Poor's	Fitch*

NSP-Minnesota NSP-Minnesota NSP-Minnesota NSP-Wisconsin NSP-Wisconsin PSCo PSCo PSCo SPS SPS	Senior Unsecured Debt Senior Secured Debt Commercial Paper Senior Unsecured Debt Senior Secured Debt Senior Unsecured Debt Senior Secured Debt Commercial Paper Senior Unsecured Debt Commercial Paper	Baa1 A3 P2 Baa1 A3 Baa2 Baa1 P2 Baa1 P2	BBB- BBB+ A3 BBB BBB+ BBB- BBB+ A3 BBB A3	BBB BBB+ F2 BBB BBB+ BBB BBB+ F2 BBB F2

Negative credit watch/negative outlook

In June 2002, the access of Xcel Energy’s Utility Subsidiaries to commercial paper markets was reduced due to lowered credit ratings (shown above). Management believes these credit ratings are unduly low given the separation of NRG’s operations and credit risk from Xcel Energy’s utility operations and financing activities. However, until the ratings are raised, Xcel Energy’s Utility Subsidiaries continue to seek sources of financing (both short- and long-term) other than commercial paper. Xcel Energy’s Utility Subsidiaries used cash or existing credit facilities to repay outstanding commercial paper obligations in July 2002. As of Sept. 30, 2002, Xcel Energy’s Utility Subsidiaries had access to cash (including available capacity under existing credit lines) as follows: $609 million at NSP-Minnesota; $553 million at PSCo; $328 million at SPS and $15 million at NSP-Wisconsin.

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

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

Capital Requirements — Dividends

The board of directors of Xcel Energy’s Utility Subsidiaries regularly reviews the respective dividend policies of the Utility Subsidiaries. Xcel Energy’s goal is to match future earnings growth with future dividend growth. Future changes to the dividend levels of Xcel Energy’s Utility Subsidiaries are subject to the evaluation and recommendation of the board of directors based on financial performance, cash requirements, and other factors to be considered.

NSP-MINNESOTA’S MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

NSP-Minnesota’s net income was approximately $158.4 million for the first nine months of 2002, compared with approximately $174.7 million for the first nine months of 2001. Most of the decrease is due to an unusual income item in 2001 related to conservation cost recovery.

Conservation Incentive Recovery

Operating income and income before income taxes in the first nine months of 2001 were increased by $41 million (before tax) due to the reversal of a MPUC decision.

In June 1999, the MPUC denied NSP-Minnesota recovery of 1998 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. The plan approved by the MPUC increased revenue by approximately $34 million and increased allowance for funds used during construction by approximately $7 million for the second quarter of 2001.

Based on the new MPUC policy and less uncertainty regarding conservation incentives to be approved, conservation incentives for 2002 are now being recorded on a current basis.

Electric Utility and Commodity Trading Margins

Electric fuel and purchased power expense tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel cost recovery mechanisms for retail customers, most fluctuations in energy costs do not affect electric utility margin.

Some electric commodity trading activity, after being initially recorded at NSP-Minnesota and PSCo, is redistributed to NSP-Minnesota, PSCo and SPS pursuant to the Joint Operating Agreement (JOA) approved by the FERC. Trading revenue and costs do not include the revenue and production costs associated with energy produced from NSP-Minnesota’s generation assets or energy and capacity purchased to serve native load. Margins from these generating assets for utility operations (excluding sales to retail and municipal customers) are included in short-term wholesale amounts, detailed below. The following table details electric utility, short-term wholesale and electric commodity trading revenue and margin:


							Electric
	Electric			Short-term			Commodity			Consolidated
(Millions of dollars)	Utility			Wholesale			Trading			Total

Nine months ended Sept. 30, 2002
Electric utility revenue	$	1,748		$	71		$	—		$	1,819
Electric fuel and purchased power-utility		(566	)		(47	)		—			(613	)
Electric trading revenue-gross		—			—			24			24
Electric trading costs		—			—			(26	)		(26	)

Gross margin before operating expenses	$	1,182		$	24		$	(2	)	$	1,204

Margin as a percentage of revenue		67.6	%		33.8	%		(8.3	)%		65.3	%
Nine months ended Sept. 30, 2001
Electric utility revenue	$	1,906		$	128		$	—		$	2,034
Electric fuel and purchased power-utility		(713	)		(94	)		—			(807	)
Electric trading revenue-gross		—			—			—			—
Electric trading costs		—			—			—			—

Gross margin before operating expenses	$	1,193		$	34		$	—		$	1,227

Margin as a percentage of revenue		62.6	%		26.6	%		—			60.3	%

Electric utility revenues decreased by $158 million, or 8.3 percent, in the first nine months of 2002, compared with the same period in 2001. This decrease is due largely to lower purchased power costs recovered through electric rates and the recovery of conservation incentives in 2001. Electric utility margins decreased by $11 million, or 0.9 percent, in the first nine months of 2002 when compared with 2001. The decrease in margins largely reflects lower shared trading margins recorded through the JOA and the recovery of conservation incentives in 2001. As discussed previously, the reversal of the MPUC decision to deny NSP-Minnesota recovery of conservation incentives increased retail revenue and margin by $34 million in the first nine months of 2001. These decreases in revenues and margin were partially offset by sales growth and lower property tax refund accruals. The margin decreases were further offset by lower capacity costs in 2002.

Short-term wholesale margins decreased in the first nine months of 2002, compared with the first nine months of 2001, due to lower power pool prices and other market conditions.

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,

(Millions of dollars)		2002			2001

Gas revenue		$	309		$	497
Cost of gas sold and transported			(210	)		(393	)

	Gas utility margin	$	99		$	104

Gas revenue decreased by approximately $188 million, or 37.8 percent, in the first nine months of 2002, compared with the same period in 2001, primarily due to decreases in the cost of natural gas, which are largely passed on to customers and recovered through various rate adjustment clauses. Gas margin for the first nine months of 2002 decreased by $5 million, or 4.8 percent, compared with the first nine months of 2001, primarily due to less favorable weather and lower margins from transportation services. These decreases were partially offset by retail sales growth.

Other Revenue

Other revenue decreased in 2002 compared to 2001 due to the transfer of certain refuse-derived fuel operations to NRG.

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expense decreased by approximately $22.0 million, or 3.5 percent, for the first nine months of 2002, compared with the first nine months of 2001. The decreased costs reflect lower incentive compensation and employee benefit costs as well as lower staffing levels by corporate areas, partially offset by higher property insurance premiums.

Depreciation and Amortization Expense increased by approximately $13.1 million, or 5.3 percent, for the first nine months of 2002, compared with the first nine months of 2001, primarily due to capital additions to utility plant.

As discussed in Note 2 to the Financial Statements, during the fourth quarter of 2001 NSP-Minnesota expensed pretax special charges for planned staff consolidation costs. In the first quarter of 2002, additional pretax special charges of $4.3 million were expensed for the final costs of staff consolidations. The charges related to NSP-Minnesota’s allocation of severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy.

Other Income (Expense) — net increased by $15.7 million, due primarily to a gain on the sale of property by a subsidiary of NSP-Minnesota, First Midwest Auto Park, in March 2002. In addition, there was increased interest income due to a Minnesota income tax settlement and higher Allowance for Funds Used During Construction from the reversal of the MPUC decision related to recovery of conservation incentives discussed previously.

Interest charges and financing costs were approximately the same for the first nine months of 2002, compared with the first nine months of 2001.

Income taxes declined in 2002 due to lower pretax income levels. Effective tax rates were approximately the same in both periods.

NSP-WISCONSIN’S MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

NSP-Wisconsin’s net income was $42.9 million for the first nine months of 2002, compared with $25.1 million for the first nine months of 2001. Most of the increase is due to lower fuel and purchased power costs.

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 recovery of all expenses and, therefore, dramatic changes in costs or periods of extreme temperatures can impact earnings.


		Nine months ended Sept. 30,

(Millions of dollars)		2002			2001

Total electric utility revenue		$	349		$	341
Electric fuel and purchased power			(160	)		(185	)

	Electric utility margin	$	189		$	156

Electric utility revenue increased by approximately $8 million, or 2.3 percent, in the first nine months of 2002, compared with the first nine months of 2001, primarily due to sales growth and higher fuel cost recovery through rates. Electric utility margin increased by approximately $33.4 million, or 21.2 percent, in the first nine months of 2002, compared with the first nine months of 2001. The increase is due to sales growth, higher fuel cost recovery through rates, and lower fuel and purchased power costs.

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


		Nine months ended Sept. 30,

(Millions of dollars)		2002			2001

Gas revenue		$	67		$	96
Cost of gas purchased and transported			(47	)		(76	)

	Gas utility margin	$	20		$	20

Gas revenue for the first nine months of 2002 decreased by approximately $29 million, or 30.2 percent, compared with the first nine months of 2001, primarily due to decreases in the cost of natural gas, which is largely recovered in Wisconsin through the purchased gas adjustment clause mechanism. Gas margin for the first nine months of 2002 was approximately the same as the first nine months of 2001.

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expense for the first nine months of 2002 decreased by $0.8 million, or 1.1 percent, compared with the first nine months of 2001, primarily due to lower incentive compensation and employee benefit costs, partially offset by higher property insurance premiums.

Depreciation and Amortization Expense increased by $2.3 million, or 7.6 percent, for the first nine months of 2002, compared with the first nine months of 2001, primarily due to capital additions to utility plant and remaining life changes to production plant and data processing equipment.

As discussed in Note 2 to the Financial Statements, during the fourth quarter of 2001, NSP-Wisconsin expensed pretax special charges for planned staff consolidation costs. In the first quarter of 2002, additional pretax special charges were

expensed for the final costs of staff consolidations. The charges related to NSP-Wisconsin’s allocation of severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy.

Other Income (Expense) — net decreased by $0.6 million due primarily to lower Allowance for Funds Used During Construction (related to lower construction expenditures) and a write down to market value on office property located in downtown Eau Claire, Wisc. Partially offsetting these items were higher interest income on economic development investments.

Interest expense increased by $1.0 million, or 5.8 percent, for the first nine months of 2002, compared with the same period in 2001, due largely to regulatory amortization of an interest refund in 2001 that did not recur in 2002 and lower Allowance for Funds Used During Construction (related to lower construction expenditures).

Income taxes increased in 2002 due to higher pretax income levels. The effective rate was approximately the same in both periods.

PSCo’S MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

PSCo’s net income was approximately $196.0 million for the first nine months of 2002, compared with approximately $221.6 million for the first nine months of 2001. The decrease is largely due to lower margins from trading and wholesale sales.

Electric Utility and Commodity Trading Margins

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 Colorado, most fluctuations in energy costs do not materially affect electric margin. 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) mechanism. 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 variable production expenses and higher costs can adversely affect earnings.

Some electric commodity trading activity, after being initially recorded at PSCo and NSP-Minnesota, is redistributed to NSP-Minnesota, PSCo and SPS pursuant to the JOA approved by the FERC. Trading revenue and costs do not include the revenue and production costs associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Margins from these generating assets for utility operations are included in short-term wholesale amounts, discussed later. Trading margins reflect the impact of sharing certain trading margins under the ICA. Trading margins, as discussed in Note 1, are reported net in the statement of income. The following table details electric utility, short-term wholesale and electric trading revenue and margin.


							Electric
	Electric			Short-term			Commodity			Consolidated
(Millions of dollars)	Utility			Wholesale			Trading			Total

Nine months ended Sept. 30, 2002
Electric utility revenue	$	1,331		$	56		$	—		$	1,387
Electric fuel and purchased power-utility		(582	)		(56	)		—			(638	)
Electric trading revenue-gross		—			—			1,327			1,327
Electric trading costs		—			—			(1,327	)		(1,327	)

Gross margin before operating expenses	$	749		$	—		$	—		$	749

Margin as a percentage of revenue		56.3	%		—			—			27.6	%
Nine months ended Sept. 30, 2001
Electric utility revenue	$	1,283		$	544		$	—		$	1,827
Electric fuel and purchased power-utility		(657	)		(433	)		—			(1,090	)
Electric trading revenue-gross		—			—			1,036			1,036
Electric trading costs		—			—			(999	)		(999	)

Gross margin before operating expenses	$	626		$	111		$	37		$	774

Margin as a percentage of revenue		48.8	%		20.4	%		3.6	%		27.0	%

Electric utility revenue increased by $48 million, or 3.7 percent, in the first nine months of 2002, compared with the first nine months of 2001. Electric utility margin increased by approximately $123 million, or 19.6 percent, in the first nine months of 2002, compared with the first nine months of 2001. The higher electric margins reflect lower unrecovered costs, due in part to resetting the base-cost recovery factor through the ICA in January 2002. Electric revenues and margin also increased due to sales growth.

Short-term wholesale margins and electric commodity trading margins decreased substantially in the first nine months of 2002, compared with the first nine months of 2001. The decrease is due to lower power pool prices, lower capacity revenues and other market conditions.

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,

(Millions of dollars)		2002			2001

Gas revenue		$	522		$	986
Cost of gas purchased and transported			(294	)		(762	)

	Gas utility margin	$	228		$	224

Gas revenue for the first nine months of 2002 decreased by approximately $464.5 million, or 47.1 percent, compared with the first nine months of 2001, largely due to lower gas costs recovered through rates. Gas margin for the first nine months of 2002 increased by approximately $4.3 million, or 1.9 percent, compared with the first nine months of 2001, primarily due to higher rates from a 2000 rate case, effective Feb. 1, 2001.

Non-Fuel Operating Expense and Other Items

Other Operation and Maintenance Expense decreased by approximately $2.9 million, or 0.9 percent, for the first nine months of 2002, compared with the first nine months of 2001. The change is primarily due to reduced bad debt reserves, lower incentive compensation and employee benefit costs as well as lower staffing levels by corporate areas, offset by higher generation maintenance overhaul costs and higher property insurance premiums.

Depreciation and Amortization Expense increased by approximately $14.8 million, or 8.4 percent, for the first nine months of 2002, compared with the first nine months of 2001, primarily due to increased amortization costs of software and increased depreciation resulting from capital additions to utility plant.

Taxes other than income taxes increased by approximately $8.1 million, or 15.1 percent, for the first nine months of 2002, compared with the first nine months of 2001, primarily due to an $8 million property tax refund received in 2001 for calendar year 2000.

Special charges decreased in 2002 compared to 2001 as discussed in Note 2. Charges in 2002 related to first quarter restaffing costs. The second quarter of 2001 included special charges related to a Colorado Supreme Court decision that resulted in a pretax write-off of $23 million of a regulatory asset related to deferred post employment benefit costs at PSCo.

Other Income (Expense) — net for the first nine months of 2001 included an $11 million pretax gain on the sale of the Boulder Hydro facility recorded in March 2001.

Income taxes declined in 2002 due to lower pretax income levels. Effective tax rates were approximately the same in both periods.

SPS’ MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

SPS’ net income was approximately $59.9 million for the first nine months of 2002, compared with approximately $94.1 million for the first nine months of 2001. Most of the decrease is due to lower electric margins.

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, SPS was authorized by the NMPRC to implement a monthly adjustment factor to recover fuel and purchased energy costs through a fuel clause. This change was effective with the February 2002 billing cycle. 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 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.


							Electric
	Electric			Short-term			Commodity		Consolidated
(Millions of dollars)	Utility			Wholesale			Trading		Total

Nine months ended Sept. 30, 2002
Electric utility revenue	$	767		$	4		$	—	$	771
Electric fuel and purchased power-utility		(411	)		(4	)		—		(415	)
Electric trading revenue-gross		—			—			—		—
Electric trading costs		—			—			—		—

Gross margin before operating expenses	$	356		$	—		$	—	$	356

Margin as a percentage of revenue		46.4	%		—			—		46.2	%
Nine months ended Sept. 30, 2001
Electric utility revenue	$	1,086		$	2		$	—	$	1,088
Electric fuel and purchased power-utility		(678	)		(1	)		—		(679	)
Electric trading revenue-gross		—			—			—		—
Electric trading costs		—			—			—		—

Gross margin before operating expenses	$	408		$	1		$	—	$	409

Margin as a percentage of revenue		37.6	%		50.0	%		—		37.6	%

Electric revenue decreased by approximately $317 million, or 29.1 percent, for the first nine months of 2002, compared with the first nine months of 2001. Electric margin decreased by approximately $53 million, or 13 percent, for the first nine months of 2002, compared with the first nine months of 2001. Electric revenues decreased largely due to decreased recovery of fuel and purchased power costs driven by declining fuel costs in 2002. Electric revenue and margin also declined due to lower shared trading margins recorded through the JOA and lower capacity sales.

Non-Fuel Operating Expense and Other Costs

Other Operation and Maintenance Expense increased by approximately $16.4 million, or 12.7 percent, for the first nine months of 2002, compared with the first nine months of 2001. The change is largely due to higher plant maintenance costs and higher plant insurance premiums, partially offset by lower incentive compensation and employee benefit costs.

Depreciation and Amortization Expense increased by approximately $4.3 million, or 7 percent, for the first nine months of 2002, compared with the first nine months of 2001, primarily due to increased amortization costs of software and capital additions to utility plant.

Special charges were incurred in 2002, mainly due to a Texas regulatory recovery adjustment and also due to an allocation of utility operations restaffing costs, as discussed in Note 2.

Interest expense was approximately the same in both periods

Income taxes decreased in 2002 due to lower pretax income levels. Effective tax rates were approximately the same in both periods.

Item 4. CONTROLS AND PROCEDURES

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

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

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against 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’ 2001 Form 10-K and Item I of Part II of their Form 10-Q for the quarter ended June 30, 2002, for a description of certain legal proceedings presently pending. There are no new significant cases to report against 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 federal district court in Minneapolis seeking reimbursement of costs for relocating electric utility lines to allow for construction of a light rail transit (LRT) line in downtown Minneapolis. In May 2001, the Minnesota Department of Transportation and the Metropolitan Council (Defendants) obtained a preliminary injunction requiring NSP-Minnesota to move certain facilities. NSP-Minnesota has complied with the preliminary injunction and utility line relocation has commenced. NSP-Minnesota is capitalizing its costs incurred as construction work in progress. In September 2002, the court granted Defendants' motions for summary judgment and dismissed NSP-Minnesota's claims. NSP-Minnesota reserves its right to appeal. In collateral matters regarding LRT construction, NSP-Minnesota commenced a mandamus action in state court seeking an order requiring Defendants to commence condemnation proceedings concerning an underground substation, access to which is blocked by LRT. In October 2002, the court dismissed NSP-Minnesota's petition. NSP-Minnesota also has commenced an action in state court alleging that LRT construction violates the Minnesota Environmental Rights Act and a separate action in federal district court alleging that the Federal Transit Administration’s failure to evaluate certain environmental effects of LRT violates the National Environmental Policy Act.

NSP-Wisconsin

Stray Voltage — On March 1, 2002, NSP-Wisconsin was served with a lawsuit commenced by James and Grace Gumz and Michael and Susan Gumz in Marathon County Circuit Court, Wisconsin, alleging that electricity supplied by NSP-Wisconsin harmed their dairy herd and caused them personal injury. The Gumz’s complaint alleges negligence, strict liability, nuisance, trespass, and statutory violations and seeks compensatory, punitive and treble damages. Plaintiffs allege compensatory damages of $1,691,940 and pre-verdict interest of $1,836,099 for total damages of $3,528,039. Trial has been set for March 2004.

On Nov. 13, 2001, Ralph Schmidt, Karline Schmidt, August C. Heeg Jr., and Joanne Heeg filed a complaint in Clark County, Wisconsin against a subsidiary of Xcel Energy. NSP-Wisconsin has been substituted as the proper party defendant, and plaintiffs will be amending their complaints to separate the Schmidt and Heeg claims into separate lawsuits. Both sets of plaintiffs allege that electricity provided by NSP-Wisconsin harmed their dairy herd resulting in decreased milk production, lost profits and income, property damage and injury to their dairy herd and seek compensatory, punitive, and treble damages. The Heeg plaintiffs allege compensatory damages of $1.9 million and pre-verdict interest of $6.1 million, for total damages of $8.0 million. The Schmidt plaintiffs allege compensatory damages of $1.0 million and pre-verdict interest of $1.2 million, for total damages of $2.2 million. No trial date has been set.

Estate of Dean E. Von Gunten v. Janice Streeter and Xcel Energy — On Sept. 20, 2002, the Estate of Dean Von Gunten filed suit in U.S. district Court, Western District of Michigan, against Janice Streeter and Xcel Energy. The complaint alleges that Ms. Streeter’s negligence in the operation of an Xcel Energy vehicle resulted in the death of plaintiff’s decedent, who was the driver of a snowmobile that collided with Xcel Energy’s vehicle. The complaint does not specify damages. Xcel Energy has answered the complaint, denying liability. Plaintiffs have agreed to substitute NSP Wisconsin as a defendant in place of Xcel Energy.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

The following Exhibits are filed with this report:


4.01		Supplemental Indenture dated Aug. 15, 2002, between PSCo and U.S. Bank Trust National Association, as trustee, creating $48,750,000 principal amount of First Mortgage Bonds, Collateral Series G, due 2019.
4.02		Supplemental Indenture dated as of Sept. 15, 2002, between PSCo and U.S. Bank Trust National Association, as trustee, creating $530,000,000 principal amount of First Mortgage Bonds, Collateral Series I, due 2003.
4.03		Supplemental Indenture dated as of Aug. 15, 2002, between PSCo and U.S. Bank Trust National Association, as trustee, creating $48,750,000 principal amount of First Collateral Trust Bonds, Series No. 7, due 2019.
4.04		Supplemental Indenture dated as of Sept. 15, 2002, between PSCo and U.S. Bank Trust National Association, as trustee, creating $530,000,000 principal amount of First Collateral Trust Bonds, Series No. 9, due 2003.
4.05		Supplemental Indenture dated as of June 1, 2002, between NSP-Minnesota and BNY Midwest Trust Company, as successor trustee, creating $308,000,000 principal amount of First Mortgage Bonds, Series due 2003.
4.06		Supplemental Indenture dated as of July 1, 2002, between NSP-Minnesota and BNY Midwest Trust Company, as successor trustee, creating $69,000,000 principal amount of First Mortgage Bonds, Pollution Control Series S.
4.07		Supplemental Indenture dated Sept. 1, 2002, between Public Service Company of Colorado and U.S. Bank Trust National Association, as Trustee, creating $600,000,000 principal amount of 7.875% First Collateral Trust Bonds, Series No. 8 due 2012. (Incorporated by reference to PSCo’s Current Report on Form 8-K, dated Sept. 18, 2002.)
4.08		Supplemental Indenture dated Sept. 18, 2002, between Public Service Company of Colorado and U.S. Bank Trust National Association, as Trustee, creating $600,000,000 principal amount of 7.875% First Mortgage Bonds, Series H due 2012. (Incorporated by reference to PSCo’s Current Report on Form 8-K, dated Sept. 18, 2002.)
4.09		Supplemental Indenture dated Aug. 1, 2002, between Northern States Power Company and BNY Midwest Trust Company, as Trustee, creating $450,000,000 principal amount of 8.00% First Mortgage Bonds, Series A due Aug. 28, 2012. (Incorporated by reference to NSP-Minnesota’s Current Report on Form 8-K, dated Aug. 22, 2002.)
99.01		Statement pursuant to Private Securities Litigation Reform Act.
99.02		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 — NSP-Minnesota.
99.03		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 — NSP-Wisconsin.
99.04		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 — PSCo.
99.05		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 — SPS.

(b) Reports on Form 8-K

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

NSP-Minnesota, NSP-Wisconsin, PSCo and SPS

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

July 8, 2002, (filed July 10, 2002) Item 5 and 7. Other Events and Exhibits. Re: NSP-MN Underwriting Agreement.

July 16, 2002, (filed July 18, 2002) Item 5 and 7. Other Events and Exhibits. Re: NSP-MN Underwriting Agreement overallotment exercise.

July 25, 2002, (filed Aug. 1, 2002) Item 5 and 7. Other Events and Exhibits. Re: Rating Agency actions and other events.

Aug. 21, 2002, (filed Aug. 22, 2002) Item 5 and 7. Other Events and Exhibits. Re: Announcement of new chief financial officer.

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

Aug. 22, 2002, (filed Aug. 26, 2002) Item 5 and 7. Other Events and Exhibits. Re: NSP-MN Purchase Agreement with several purchasers (private placement) of debt securities.

Sept. 18, 2002 (filed Sept. 27, 2002) Item 5 and 7. Other Events and Exhibits. Re: PSCo Purchase Agreement with several purchasers (private placement) of debt securities.

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. 14, 2002.


		Northern States Power Co. (a Minnesota corporation)

		(Registrant)


		/s/ DAVID E. RIPKA

		David E. Ripka Vice President and Controller


		/s/ RICHARD C, KELLY

		Richard C. Kelly Vice President and Chief Financial Officer

NORTHERN STATES POWER CO. (A MINNESOTA CORPORATION) CERTIFICATIONS

I, Wayne H. Brunetti, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Northern States Power Co. (A Minnesota Corporation);

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

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

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

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

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

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

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

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

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

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


Date: Nov. 14, 2002

		/s/ WAYNE H. BRUNETTI

		Wayne H. Brunetti Chairman, President and Chief Executive Officer

I, Richard C. Kelly, certify that:


Date: Nov. 14, 2002

		/s/ RICHARD C. KELLY

		Richard C. Kelly Vice President and Chief Financial Officer

NORTHERN STATES POWER CO. (A WISCONSIN CORPORATION) SIGNATURES


		Northern States Power Co. (a Wisconsin corporation)

		(Registrant)


		/s/ DAVID E. RIPKA

		David E. Ripka Vice President and Controller


		/s/ RICHARD C. KELLY

		Richard C. Kelly Vice President and Chief Financial Officer

NORTHERN STATES POWER CO. (A WISCONSIN CORPORATION) CERTIFICATIONS

I, Wayne H. Brunetti, certify that:

5. I have reviewed this quarterly report on Form 10-Q of Northern States Power Co. (A Wisconsin Corporation);

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

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

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

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

e) evaluated in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

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

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

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

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

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


Date: Nov. 14, 2002

		/s/ WAYNE H. BRUNETTI

		Wayne H. Brunetti Chairman, President and Chief Executive Officer

I, Richard C. Kelly, certify that:


Date: Nov. 14, 2002

		/s/ RICHARD C. KELLY

		Richard C. Kelly Vice President and Chief Financial Officer

PUBLIC SERVICE CO. OF COLORADO SIGNATURES


		Public Service Co. of Colorado

		(Registrant)

		/s/ DAVID E. RIPKA

		David E. Ripka Vice President and Controller


		/s/ RICHARD C. KELLY

		Richard C. Kelly Vice President and Chief Financial Officer

PUBLIC SERVICE CO. OF COLORADO CERTIFICATIONS

I, Wayne H. Brunetti, certify that:

9. I have reviewed this quarterly report on Form 10-Q of Public Service Co. of Colorado;

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

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

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

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

h) evaluated in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

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

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

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

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

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


Date: Nov. 14, 2002

		/s/ WAYNE H. BRUNETTI

		Wayne H. Brunetti Chairman, President and Chief Executive Officer

I, Richard C. Kelly, certify that:


Date: Nov. 14, 2002

		/s/ RICHARD C. KELLY

		Richard C. Kelly Vice President and Chief Financial Officer

SOUTHWESTERN PUBLIC SERVICE CO. SIGNATURES


		Southwestern Public Service Co.

		(Registrant)

		/s/ DAVID E. RIPKA

		David E. Ripka Vice President and Controller


		/s/ RICHARD C. KELLY

		Richard C. Kelly Vice President and Chief Financial Officer

SOUTHWESTERN PUBLIC SERVICE CO. CERTIFICATIONS

I, Gary L. Gibson, certify that:

13. I have reviewed this quarterly report on Form 10-Q of Southwestern Public Service Co;

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

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

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

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

k) evaluated in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

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

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

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

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

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


Date: Nov. 14, 2002

		/s/ GARY L. GIBSON

		Gary L. Gibson President and Chairman

I, Richard C. Kelly, certify that:


Date: Nov. 14, 2002

		/s/ RICHARD C. KELLY

		Richard C. Kelly Vice President and Chief Financial Officer

	•		November 2002 — intervenor testimony;

	•		January 2003 — company rebuttal testimony;

	•		February/March 2003 — hearings; and

	•		April/May 2003 — rates effective.

•		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 and federal 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 and other western 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, 2002.

1.		I have reviewed this quarterly report on Form 10-Q of Northern States Power Co. (A Minnesota Corporation);

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

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

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

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

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

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

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

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