NORTHERN STATES POWER CO - 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 March 31, 2003

		OR

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

		For the transition period from to


	Exact name of registrant as specified in its charter, State or
	other 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.

001-31387	NORTHERN STATES POWER COMPANY (a Minnesota Corporation) 414 Nicollet Mall, Minneapolis, Minn. 55401 Telephone (612) 330-5500	41-1967505

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

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

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

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

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

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.


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

TABLE OF CONTENTS


PART 1. FINANCIAL INFORMATION
	Item 1. Consolidated Financial Statements
	Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
	Item 4. CONTROLS AND PROCEDURES
Part II. OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 6. Exhibits and Reports on Form 8-K
EX-4.01 Supplemental Indenture
EX-4.02 Supplemental Indenture
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	23
	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	29
Item 6.	Exhibits and Reports on Form 8-K	30

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). Xcel Energy is a registered holding company under the Public Utility Holding Company Act (PUHCA). Additional information on Xcel Energy is available on various filings with the SEC.

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

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

PART 1. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

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


				Three Months Ended March 31

				2003			2002

Operating revenues:
	Electric utility			$	586,911		$	537,882
	Electric trading margin				1,400			3,100
	Natural gas utility				333,250			187,536
	Other				6,194			6,733

			Total operating revenues		927,755			735,251
Operating expenses:
	Electric fuel and purchased power				208,990			184,445
	Cost of natural gas sold and transported				268,692			128,488
	Other operating and maintenance expenses				211,610			221,874
	Depreciation and amortization				91,202			85,432
	Taxes (other than income taxes)				44,346			43,318
	Special charges (see Note 2)				—			4,324

			Total operating expenses		824,840			667,881

Operating income					102,915			67,370
Other income (expense):
	Interest income				1,900			1,469
	Other nonoperating income				2,600			8,287
	Nonoperating expense				(1,480	)		(1,092	)

		Total other income (expense)			3,020			8,664
Interest charges and financing costs:
	Interest charges — net of amounts capitalized, includes other financing costs of $1,734 and $1,159, respectively				31,974			17,575
	Distributions on redeemable preferred securities of subsidiary trust				3,938			3,938

			Total interest charges and financing costs		35,912			21,513

Income before income taxes					70,023			54,521
Income taxes					25,572			21,488

Net income				$	44,451		$	33,033

See disclosures regarding NSP-Minnesota in the Notes to Consolidated Financial Statements

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


				Three Months Ended March 31

				2003			2002

Operating activities:
	Net income			$	44,451		$	33,033
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			93,533			87,361
		Nuclear fuel amortization			11,791			12,037
		Deferred income taxes			(10,395	)		(20,277	)
		Amortization of investment tax credits			(1,841	)		(2,212	)
		Allowance for equity funds used during construction			(2,009	)		(1,488	)
		Gain on sale of property			—			(6,785	)
		Change in accounts receivable			(54,250	)		(18,015	)
		Change in inventories			25,375			10,500
		Change in other current assets			(14,683	)		15,946
		Change in accounts payable			7,997			(14,261	)
		Change in other current liabilities			3,775			56,573
		Change in other noncurrent assets			1,261			(14,688	)
		Change in other noncurrent liabilities			14,217			24,854

			Net cash provided by operating activities		119,222			162,578
Investing activities:
	Capital/construction expenditures				(90,564	)		(88,010	)
	Proceeds from sale of property				—			11,152
	Allowance for equity funds used during construction				2,009			1,488
	Investments in external decommissioning fund				(8,406	)		(14,259	)
	Other investments — net				(1,638	)		(963	)

		Net cash used in investing activities			(98,599	)		(90,592	)
Financing activities:
	Short-term borrowings — net				(2	)		(5,142	)
	Repayment of long-term debt, including reacquisition premiums				(107,790	)		(278	)
	Dividends paid to parent				(52,280	)		(44,332	)

		Net cash used in financing activities			(160,072	)		(49,752	)
Net (decrease) increase in cash and cash equivalents					(139,449	)		22,234
Cash and cash equivalents at beginning of year					310,338			17,169

Cash and cash equivalents at end of year				$	170,889		$	39,403

See disclosures regarding NSP-Minnesota in the Notes to Consolidated Financial Statements

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


			March 31			Dec. 31
			2003			2002

ASSETS
Current assets:
	Cash and cash equivalents		$	170,889		$	310,338
	Restricted cash			23,000			23,000
	Accounts receivable — net of allowance for bad debts: $5,777 and $5,812, respectively			294,087			231,996
	Accounts receivable from affiliates			16,932			24,773
	Accrued unbilled revenues			131,166			109,435
	Materials and supplies inventories — at average cost			105,972			106,037
	Fuel inventory — at average cost			29,589			34,875
	Natural gas inventory — at average cost			4,361			24,385
	Derivative instrument valuation — at market			5,482			3,831
	Prepayments and other			22,300			34,234

		Total current assets		803,778			902,904

Property, plant and equipment, at cost:
	Electric utility plant			7,012,661			6,855,807
	Natural gas utility plant			720,989			716,844
	Construction work in progress			354,736			313,931
	Other			385,322			384,214

		Total property, plant and equipment		8,473,708			8,270,796
	Less accumulated depreciation			(4,167,217	)		(4,624,988	)
	Nuclear fuel — net of accumulated amortization: $1,070,322 and $1,058,531, respectively			85,567			74,139

		Net property, plant and equipment		4,392,058			3,719,947

Other assets:
	Nuclear decommissioning fund investments			617,650			617,048
	Other investments			23,896			22,730
	Regulatory assets			396,700			212,539
	Prepaid pension asset			276,383			263,713
	Other			64,500			72,144

		Total other assets		1,379,129			1,188,174

		Total assets	$	6,574,965		$	5,811,025

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	118,715		$	226,462
	Short-term debt			67			69
	Accounts payable			230,079			198,889
	Accounts payable to affiliates			43,673			66,866
	Taxes accrued			214,000			210,041
	Accrued interest			27,271			44,167
	Dividends payable to parent			53,569			52,280
	Derivative instrument valuation — at market			4,791			3,958
	Other			57,526			39,297

		Total current liabilities		749,691			842,029

Deferred credits and other liabilities:
	Deferred income taxes			684,304			700,966
	Deferred investment tax credits			72,603			74,577
	Regulatory liabilities			490,337			486,035
	Asset retirement obligations (see Note 1)			875,937			—
	Benefit obligations and other			140,075			136,452

		Total deferred credits and other liabilities		2,263,256			1,398,030

Long-term debt				1,570,112			1,569,938
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				813,869			813,869
Retained earnings				978,041			987,158
Accumulated other comprehensive (loss) income				(14	)		(9	)

	Total common stockholder’s equity			1,791,906			1,801,028
Commitments and contingencies (see Note 4)

Total liabilities and equity			$	6,574,965		$	5,811,025

See disclosures regarding NSP-Minnesota in the Notes to Consolidated Financial Statements

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


			Three Months Ended March 31

			2003			2002

Operating revenues:
	Electric utility		$	120,526		$	116,922
	Natural gas utility			64,433			40,394
	Other			87			86

		Total operating revenues		185,046			157,402
Operating expenses:
	Electric fuel and purchased power			55,463			54,531
	Cost of natural gas sold and transported			50,656			29,234
	Other operating and maintenance expenses			24,438			23,588
	Depreciation and amortization			11,334			10,755
	Taxes (other than income taxes)			4,227			4,100
	Special charges (see Note 2)			—			512

		Total operating expenses		146,118			122,720
Operating income				38,928			34,682
Other income (expense):
	Interest income			161			697
	Other nonoperating income			262			181
	Nonoperating expense			(102	)		(56	)

		Total other income (expense)		321			822
Interest charges — net of amounts capitalized; includes other financing costs of $224 and $224, respectively				5,731			5,833

Income before income taxes				33,518			29,671
Income taxes				13,664			11,720

Net income			$	19,854		$	17,951

See disclosures regarding NSP-Wisconsin in the Notes to Consolidated Financial Statements

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


				Three Months Ended March 31

				2003			2002

Operating activities:
	Net income			$	19,854		$	17,951
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			11,591			11,060
		Deferred income taxes			668			155
		Amortization of investment tax credits			(198	)		(202	)
		Allowance for equity funds used during construction			(207	)		(184	)
		Undistributed equity in earnings of unconsolidated affiliates			(2	)		(62	)
		Change in accounts receivable			(7,657	)		(15,218	)
		Change in inventories			3,950			4,101
		Change in other current assets			4,483			9,469
		Change in accounts payable			1,968			6,800
		Change in other current liabilities			16,532			14,288
		Change in other assets			(834	)		(3,387	)
		Change in other liabilities			(675	)		(330	)

			Net cash provided by operating activities		49,473			44,441
Investing activities:
	Capital/construction expenditures				(9,155	)		(8,037	)
	Allowance for equity funds used during construction				207			184
	Other investments — net				(10	)		(81	)

			Net cash used in investing activities		(8,958	)		(7,934	)
Financing activities:
	Short-term borrowings from affiliate — net				(6,880	)		(25,500	)
	Dividends paid to parent				(12,260	)		(11,006	)

			Net cash used in financing activities		(19,140	)		(36,506	)

Net increase in cash and cash equivalents					21,375			1
Cash and cash equivalents at beginning of period					98			30

Cash and cash equivalents at end of period				$	21,473		$	31

See disclosures regarding NSP-Wisconsin in the Notes to Consolidated Financial Statements

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


				March 31			Dec. 31
				2003			2002

ASSETS
Current assets:
	Cash and cash equivalents			$	21,473		$	98
	Accounts receivable — net of allowance for bad debts: $835 and $1,373, respectively				55,354			47,890
	Accounts receivable from affiliates				1,653			1,460
	Accrued unbilled revenues				22,112			20,074
	Materials and supplies inventories — at average cost				5,941			5,994
	Fuel inventory — at average cost				5,340			6,006
	Natural gas inventory — at average cost				1,032			4,263
	Current deferred income taxes				6,751			—
	Prepaid taxes				10,496			13,735
	Prepayments and other				1,234			1,681

		Total current assets			131,386			101,201

Property, plant and equipment, at cost:
	Electric utility plant				1,171,169			1,161,901
	Natural gas utility plant				133,064			131,969
	Construction work in progress				20,144			18,305
	Other				92,825			95,631

			Total property, plant and equipment		1,417,202			1,407,806
	Less accumulated depreciation				(603,757	)		(592,187	)

		Net property, plant and equipment			813,445			815,619

Other assets:
	Other investments				9,829			9,817
	Regulatory assets				47,288			48,112
	Prepaid pension asset				40,446			38,557
	Other				7,106			7,577

			Total other assets		104,669			104,063

			Total assets	$	1,049,500		$	1,020,883

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt			$	40,034		$	40,034
	Short-term debt — notes payable to affiliate				—			6,880
	Accounts payable				27,780			23,535
	Accounts payable to affiliates				4,559			6,836
	Dividends payable to parent				12,455			12,260
	Other				36,757			20,225

			Total current liabilities		121,585			109,770

Deferred credits and other liabilities:
	Deferred income taxes				156,725			146,471
	Deferred investment tax credits				14,622			14,820
	Regulatory liabilities				11,891			11,950
	Benefit obligations and other				45,412			46,026

			Total deferred credits and other liabilities		228,650			219,267

Long-term debt					273,129			273,108
Common stock — authorized 1,000,000 shares of $100 par value; outstanding 933,000 shares					93,300			93,300
Premium on common stock					62,981			62,981
Retained earnings					269,855			262,457

			Total common stockholder’s equity		426,136			418,738
Commitments and contingent liabilities (see Note 4)

Total liabilities and equity				$	1,049,500		$	1,020,883

See disclosures regarding NSP-Wisconsin in the Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(Thousands of dollars)


					Three Months ended March 31,

					2003			2002

Operating revenues:
		Electric utility			$	494,489		$	437,649
		Electric trading margin				(2,051	)		(3,599	)
		Natural gas utility				256,677			316,865
		Steam and other				6,648			7,765

				Total operating revenues		755,763			758,680
Operating expenses:
		Electric fuel and purchased power				255,795			209,168
		Cost of natural gas sold and transported				154,907			210,844
		Cost of sales — steam and other				3,698			1,525
		Other operating and maintenance expenses				114,768			117,318
		Depreciation and amortization				58,643			64,564
		Taxes (other than income taxes)				20,181			22,272
		Special charges (see Note 2)				—			131

				Total operating expenses		607,992			625,822

Operating income						147,771			132,858
Other income (expense):
	Interest income					441			96
	Other nonoperating income					1,562			1,279
	Nonoperating expenses					(3,204	)		(2,467	)

			Total other income (expense)			(1,201	)		(1,092	)

Interest charges and financing costs:
		Interest charges — net of amounts capitalized, includes other financing costs of $1,716 and $869, respectively				35,917			27,655
		Distributions on redeemable preferred securities of subsidiary trust				3,686			3,800

				Total interest charges and financing costs		39,603			31,455

Income before income taxes and extraordinary item						106,967			100,311
Income taxes						36,880			33,620

Net income					$	70,087		$	66,691

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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


				Three Months Ended March 31,

				2003			2002

Operating activities:
	Net income			$	70,087		$	66,691
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			61,509			65,434
		Deferred income taxes			52,061			11,395
		Amortization of investment tax credits			(1,833	)		(1,022	)
		Allowance for equity funds used during construction			(269	)		2
		Change in accounts receivable			(40,948	)		(44,791	)
		Change in unbilled revenue			83,157			23,702
		Change in recoverable natural gas and electric costs			(93,100	)		(42,445	)
		Change in inventories			47,954			38,459
		Change in other current assets			(8,054	)		(9,103	)
		Change in accounts payable			(61,476	)		(55,463	)
		Change in other current liabilities			45,668			83,789
		Change in other assets			2,302			(17,327	)
		Change in other liabilities			7,863			13,627

			Net cash provided by operating activities		164,921			132,948
Investing activities:
	Capital/construction expenditures				(78,694	)		(86,162	)
	Proceeds from disposition of property, plant and equipment				1,371			6,363
	Allowance for equity funds used during construction				269			(2	)
	Other investments — net				(313	)		1,769

			Net cash used in investing activities		(77,367	)		(78,032	)
Financing activities:
	Short-term borrowings — net				(88,537	)		(46,159	)
	Proceeds from issuance of long-term debt				247,277			—
	Repayment of long-term debt, including reacquisition premiums				(2,012	)		(568	)
	Capital contributions from parent				—			50,000
	Dividends paid to parent				(60,550	)		(53,387	)

			Net cash provided by (used in) financing activities		96,178			(50,114	)

	Net increase in cash and cash equivalents				183,732			4,802
	Cash and cash equivalents at beginning of period				25,924			22,666

	Cash and cash equivalents at end of period			$	209,656		$	27,468

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(Thousands of dollars)


				March 31,			Dec. 31,
				2003			2002

ASSETS
Current assets:
	Cash and cash equivalents			$	209,656		$	25,924
	Accounts receivable — net of allowance for bad debts: $14,215 and $13,685, respectively				209,410			165,743
	Accounts receivable from affiliates				16,689			19,407
	Accrued unbilled revenues				120,812			203,969
	Recoverable purchased natural gas and electric energy costs				128,518			23,131
	Materials and supplies inventories — at average cost				49,153			49,579
	Fuel inventory — at average cost				23,205			25,366
	Natural gas inventories — replacement cost in excess of LIFO: $31,985 and $20,502, respectively				40,312			85,679
	Derivative instruments valuation — at market				5,178			2,735
	Prepayments and other				21,311			13,257

			Total current assets		824,244			614,790

Property, plant and equipment, at cost:
	Electric utility plant				5,393,620			5,345,464
	Natural gas utility plant				1,511,331			1,494,017
	Construction work in progress				481,633			456,800
	Other				626,101			624,764

			Total property, plant and equipment		8,012,685			7,921,045
	Less accumulated depreciation				(2,951,835	)		(2,896,978	)

			Net property, plant and equipment		5,060,850			5,024,067

Other assets:
	Other investments				8,317			12,319
	Regulatory assets				219,846			238,600
	Other				39,434			35,150

			Total other assets		267,597			286,069

			Total assets	$	6,152,691		$	5,924,926

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt			$	427,106		$	282,097
	Short-term debt				—			88,074
	Note payable to affiliate				14,679			15,142
	Accounts payable				263,940			318,005
	Accounts payable to affiliates				32,968			40,449
	Taxes accrued				65,888			47,363
	Dividends payable to parent				58,846			60,550
	Derivative instruments valuation — at market				6,125			2,593
	Current deferred income tax				58,777			22,298
	Accrued interest				52,220			44,391
	Other				72,062			53,574

			Total current liabilities		1,052,611			974,536

Deferred credits and other liabilities:
	Deferred income taxes				566,301			553,006
	Deferred investment tax credits				73,979			74,987
	Regulatory liabilities				45,097			45,707
	Customers advances for construction				162,828			142,992
	Minimum pension liability				104,773			104,773
	Benefit obligations and other				77,373			74,335

			Total deferred credits and other liabilities		1,030,351			995,800

Long-term debt					1,884,354			1,782,128
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					1,652,284			1,652,284
Retained earnings					442,237			430,997
Accumulated comprehensive income (loss)					(103,146	)		(104,819	)

		Total common stockholder’s equity			1,991,375			1,978,462
Commitments and contingencies (see Note 4)

			Total liabilities and equity	$	6,152,691		$	5,924,926

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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


			Three Months Ended March 31

			2003			2002

Operating revenues			$	244,597		$	211,692
Operating expenses:
	Electric fuel and purchased power			140,188			97,976
	Other operating and maintenance expenses			42,844			39,516
	Depreciation and amortization			21,512			22,004
	Taxes (other than income taxes)			11,730			11,758
	Special charges (see Note 2)			—			5,321

		Total operating expenses		216,274			176,575
Operating income				28,323			35,117
Other income (expense):
	Interest income			1,138			715
	Other nonoperating income			577			1,136
	Nonoperating expense			(35	)		(3	)

		Total other income (expense)		1,680			1,848
Interest charges and financing costs:
	Interest charges — net of amounts capitalized; includes other financing costs of $1,639 and $1,535 respectively			11,732			11,392
	Distributions on redeemable preferred securities of subsidiary trust			1,963			1,963

		Total interest charges and financing costs		13,695			13,355
Income before income taxes				16,308			23,610
Income taxes				6,217			8,862

Net income			$	10,091		$	14,748

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

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


				Three Months Ended March 31

				2003			2002

Operating activities:
	Net income			$	10,091		$	14,748
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			23,298			23,826
		Deferred income taxes			4,491			4,092
		Amortization of investment tax credits			(63	)		(62	)
		Allowance for equity funds used during construction			(575	)		(206	)
		Change in recoverable electric energy costs			(1,415	)		(39,883	)
		Change in accounts receivable			(34,216	)		(9,178	)
		Change in inventories			390			(1,213	)
		Change in other current assets			7,802			40,570
		Change in accounts payable			31,218			7,980
		Change in other current liabilities			(3,873	)		(1,969	)
		Change in other noncurrent assets			(3,581	)		(7,391	)
		Change in other noncurrent liabilities			1,493			1,969

			Net cash provided by operating activities		35,060			33,283
Investing activities:
	Capital/construction expenditures				(20,690	)		(6,478	)
	Allowance for equity funds used during construction				575			206
	Other investments — net				257			(1,073	)

			Net cash used in investing activities		(19,858	)		(7,345	)
Financing activities:
	Dividends paid to parent				(24,428	)		(60,969	)

			Net cash used in financing activities		(24,428	)		(60,969	)

	Net decrease in cash and cash equivalents				(9,226	)		(35,031	)
	Cash and cash equivalents at beginning of period				60,700			65,499

	Cash and cash equivalents at end of period			$	51,474		$	30,468

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

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


			March 31			Dec. 31
			2003			2002

ASSETS
Current assets:
	Cash and cash equivalents		$	51,474		$	60,700
	Accounts receivable — net of allowance for bad debts: $1,463 and $1,559, respectively			95,493			49,460
	Accounts receivable from affiliates			10,970			22,787
	Accrued unbilled revenues			44,053			52,999
	Recoverable electric energy costs			17,854			16,439
	Materials and supplies inventories — at average cost			16,212			17,231
	Fuel inventories — at average cost			1,951			1,322
	Prepayments and other			7,353			6,059

		Total current assets		245,360			226,997

Property, plant and equipment, at cost:
	Electric utility plant			3,075,826			3,076,970
	Other and construction work in progress			74,666			64,908

		Total property, plant and equipment		3,150,492			3,141,878
	Less accumulated depreciation			(1,346,471	)		(1,338,340	)

		Net property, plant and equipment		1,804,021			1,803,538

Other assets:
	Other investments			14,125			14,382
	Regulatory assets			103,108			105,404
	Prepaid pension asset			108,357			105,044
	Deferred charges and other			9,091			9,979

		Total other assets		234,681			234,809

		Total assets	$	2,284,062		$	2,265,344

LIABILITIES AND EQUITY
Current liabilities:
	Accounts payable		$	104,836		$	73,536
	Accounts payable to affiliates			9,522			9,604
	Taxes accrued			17,048			24,107
	Accrued interest			11,167			7,630
	Dividends payable to parent			24,649			24,427
	Current portion of accumulated deferred income taxes			14,825			13,034
	Derivative instruments valuation — at market			1,123			1,176
	Other			22,122			22,473

		Total current liabilities		205,292			175,987

Deferred credits and other liabilities:
	Deferred income taxes			402,309			399,800
	Deferred investment tax credits			4,154			4,217
	Regulatory liabilities			2,328			2,363
	Derivative instruments valuation — at market			5,636			6,008
	Benefit obligations and other			24,090			22,597

		Total deferred credits and other liabilities		438,517			434,985

Long-term debt				725,734			725,662
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				411,329			411,329
Retained earnings				407,417			421,976
Accumulated other comprehensive income (loss)				(4,227	)		(4,595	)

		Total common stockholder’s equity		814,519			828,710
Commitments and contingencies (see Note 4)

		Total liabilities and equity	$	2,284,062		$	2,265,344

See disclosures regarding SPS in the Notes to Consolidated 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 March 31, 2003, and Dec. 31, 2002, the results of their operations for the three months ended March 31, 2003 and 2002, and their cash flows for the three months ended March 31, 2003 and 2002. Due to the seasonality of electric and natural 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 their financial statements in their respective Annual Reports on Form 10-K for the year ended Dec. 31, 2002. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K’s.

We reclassified certain items in the 2002 income statement to conform to the presentation disclosed in the 2002 Annual Report on Form 10-K. These reclassifications had no effect on stockholders’ equity, net income or earnings per share as previously reported. The reclassifications were primarily to conform the presentation of all consolidated Xcel Energy subsidiaries to a standard corporate presentation.

1. Accounting Changes — Asset Retirement Obligations (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

The Utility Subsidiaries of Xcel Energy adopted Statement of Financial Accounting Standard (SFAS) No. 143, “Accounting for Asset Retirement Obligations” effective Jan. 1, 2003. As required by SFAS No. 143, future plant decommissioning obligations were recorded as a liability at fair value as of Jan. 1, 2003, with a corresponding increase to the carrying values of the related long-lived assets. This liability will be increased over time by applying the interest method of accretion to the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets. Since SFAS No. 143 will primarily affect Xcel Energy’s utility subsidiaries, the adoption of the statement had no income statement impact, as the cumulative effect adjustments required under SFAS No. 143 have been deferred through the establishment of a regulatory asset pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.”

Asset retirement obligations were recorded for the decommissioning of two NSP-Minnesota nuclear generating plants, the Monticello plant and the Prairie Island plant. A liability was also recorded for decommissioning of an NSP-Minnesota steam production plant, the Pathfinder plant. Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are licensed to operate until 2013 and 2014, respectively. Pathfinder operated as a steam production peaking facility from 1969 through June of 2000.

A summary of the accounting for the initial adoption of SFAS No. 143 is as follows (in thousands of dollars):


		Increase (decrease) in:

					Regulatory			Long-term
		Plant Assets			Assets			Liabilities

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

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

A reconciliation of the beginning and ending aggregate carrying amount of NSP-Minnesota’s asset retirement obligations recorded under SFAS No. 143 is shown in the table below for the three months ending March 31, 2003.

(Thousands of dollars)


				Quarter Ended March 31, 2003

												Ending
		Beginning								Revisions		Balance
		Balance Jan.		Liabilities		Liabilities				to Prior		March 31,
Obligation		1, 2003		Incurred		Settled		Accretion		Estimates		2003

Steam plant retirement		$	2,725	$	—	$	—	$	33	$	—	$	2,758
Nuclear plant decommissioning			859,643		—		—		13,536		—		873,179

	Total liability	$	862,368	$	—	$	—	$	13,569	$	—	$	875,937

The adoption of SFAS No. 143 resulted in the recording of a capitalized plant asset of $131 million for the discounted cost of asset retirement as of the date the liability was incurred. Accumulated depreciation on this additional capitalized cost

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

The following pro-forma liabilities reflect amounts as if SFAS No. 143 had been applied during all periods reported (in millions):


		Dec. 31,

Liability		2002

Steam production		$	2.7
Nuclear decommissioning			859.6

	Total pro-forma liability	$	862.3

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

The fair value of the assets legally restricted for purposes of settling the nuclear asset retirement obligations is $665 million as of March 31, 2003.

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


(Millions of Dollars)

NSP-Minnesota	$	304
NSP-Wisconsin		70
PSCo.		329
SPS		97

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

2002 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, which was approved by the state regulatory commission in May 2002. 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 recorded an estimated liability for expected staff consolidation costs for an estimated 500 employees in several utility operating and corporate support areas of Xcel Energy. In the first quarter of 2002, the identification of affected employees was completed and additional pretax special charges of $9 million were expensed for the final costs of the utility related staff consolidations. All 564 of accrued staff terminations have occurred.

------------------------ ------------------------

The following table summarizes the activity related to accrued special charges for the first three months of 2003 (in thousands of dollars).


			Dec. 31, 2002		Accrued Special					March 31, 2003
			Liability		Charges		Payments			Liability

Employee severance and related costs			$	13,120	$	—	$	(6,415	)	$	6,705

	Total accrued special charges — Xcel Energy		$	13,120	$	—	$	(6,415	)	$	6,705

Employee severance and related costs for Utility Subsidiaries:
NSP-Minnesota			$	1,567	$	—	$	(938	)	$	629
NSP-Wisconsin				171		—		(108	)		63
PSCo				267		—		(212	)		55
SPS				250		—		(155	)		95

		Total accrued special charges — Utility Subs	$	2,255	$	—	$	(1,413	)	$	842

3. Regulation (PSCo and SPS)

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

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

• an interim adjustment clause (IAC) that recovers 100 percent of prudently incurred 2003 electric fuel and purchased energy expense above the expense recovered through electric base rates during 2003. This clause is projected to recover energy costs totaling approximately $216 million in 2003. The IAC originally went into effect on Jan. 1, 2003. The IAC rate was increased on May 1, 2003 by $93 million to recover the total anticipated energy costs for 2003;

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

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

Hearings on one settlement agreement were held in late April 2003. Management believes the CPUC will approve the settlement agreement and issue a final rate order during the second quarter, with new rates effective as discussed above. PSCo will now move to the phase II, rate design, portion of the case.

PSCo Fuel Adjustment Clause Proceedings — Certain wholesale power customers of PSCo have filed complaints with the FERC alleging PSCo has been improperly collecting certain fuel and purchased energy costs through the wholesale fuel cost adjustment clause included in their rates. The FERC consolidated these complaints and set them for hearing and settlement judge procedures. In November 2002, the Chief Judge terminated settlement procedures after settlement was not reached. The complainants’ filed initial testimony in late April 2003 claiming the improper inclusion of fuel and purchased energy costs in the range of $40-50 million related to the 1996 to 2002 period. PSCo is currently analyzing the testimony and will file rebuttal testimony in June 2003. The hearings are scheduled for August 2003.

PSCo had an Incentive Cost Adjustment (ICA) for periods prior to calendar 2003, as disclosed in the 2002 Form 10-K. The CPUC is conducting a proceeding to review and approve the incurred and recoverable 2001 costs under the ICA. In April 2003, the CPUC Staff and an intervenor filed testimony recommending disallowance of fuel and purchased energy costs, which, if granted, would result in a $30 million reduction in recoverable 2001 ICA costs. PSCo is currently analyzing the testimony of the CPUC Staff and the intervenor and will file rebuttal testimony in June 2003. The hearings on this matter are scheduled to commence in July 2003. If CPUC Staff and the intervenor are successful, recommended disallowances would also result in a reduction of the recoverable 2002 ICA costs. A review of the 2002 recoverable ICA costs will be conducted in a future proceeding.

At March 31, 2003, PSCo has recorded its deferred fuel and purchased energy costs based on the expected rate recovery of its costs as filed in the above rate proceedings, without the adjustments proposed by various parties. Pending the

outcome of these regulatory proceedings, we cannot at this time determine whether any customer refunds or disallowances of PSCo’s deferred costs will be required.

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

SPS has reported to the PUCT that it has under-collected its fuel costs under the current Texas retail fixed fuel factors. In May 2003, SPS proposed to surcharge $13.2 million and related interest for fuel cost under-recoveries incurred through March 2003. The surcharge will be amortized and collected over an eight-month period. Recovery amounts would depend on future fuel rates once the filing is approved.

4. 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, 2002, 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 — Internal Revenue Service issue of Notice of Proposed Adjustment regarding the tax deductibility of corporate owned life insurance loan interest deductions taken in tax years beginning in 1993

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

NSP-Minnesota

At March 31, 2003, NSP-Minnesota had approximately $0.1 million of short-term debt outstanding at a weighted average interest rate of 8.5 percent.

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

PSCo

At March 31, 2003, PSCo had no short-term debt outstanding.

In March 2003, PSCo issued $250 million of first collateral trust bonds. These bonds carry a fixed interest rate of 4.875 percent and mature in 2013. The proceeds were used to repay outstanding short-term debt and to pay long-term debt at maturity.

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

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

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

The impact of the components of SFAS No. 133 on Other Comprehensive Income, included in Stockholders’ Equity, are detailed in the following table:


	Three months ended
	March 31, 2003

	NSP-
(Millions of dollars)	Minnesota		PSCo		SPS

Balance at Jan. 1, 2003	$	0.0	$	1.0	$	(4.6	)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		0.0		1.3		0.4
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		0.0		0.4		0.0

Accumulated other comprehensive (loss) income related to SFAS No. 133 — March 31, 2003	$	0.0	$	2.7	$	(4.2	)


	Three months ended
	March 31, 2002

	NSP-
(Millions of dollars)	Minnesota			PSCo			SPS

Balance at Jan. 1, 2002	$	0.1		$	(4.3	)	$	(4.4	)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		(0.1	)		8.7			(0.3	)
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(0.2	)		(0.8	)		0.2

Accumulated other comprehensive (loss) income related to SFAS No. 133 — March 31, 2002	$	(0.2	)	$	3.6		$	(4.5	)

Cash Flow Hedges

NSP-Minnesota, PSCo and SPS enter into derivative instruments to manage their 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 March 31, 2003, NSP-Minnesota, PSCo and SPS had various commodity-related contracts extending through 2009. Amounts deferred in Other Comprehensive Income are recorded as the hedged purchase or sales transaction is completed. This could include the physical sale of electric energy or the use of natural gas to generate electric energy. As of March 31, 2003, PSCo had net gains of $1.7 million accumulated in Other Comprehensive Income that are expected to be recognized in earnings during the next 12 months as the hedged transaction occurs. However, due to the volatility of commodities markets, the value in Other Comprehensive Income will likely change prior to its recognition in earnings. SPS’ other comprehensive income expected to be recognized during the next 12 months is not material.

As required by SFAS No. 133, PSCo recorded gains of $0 and $0.1 million related to ineffectiveness on commodity cash flow hedges during the three months ended March 31, 2003 and 2002, respectively.

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 March 2004 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 Operations. All derivative instruments are recorded at the amount of the gain or loss from the transaction within Operating Revenues on the Consolidated Statements of Operations.

Normal Purchases or Normal Sales

Xcel Energy’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 to determine if they are derivatives and if so, if they qualify and meet the normal designation requirements under SFAS No. 133. None of the contracts entered into within the trading operations qualify for a normal designation.

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

Pending Accounting Change

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

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

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

(Thousands of dollars)

NSP-Minnesota


				Natural
Three months ended		Electric		Gas		All		Consolidated
March 31, 2003		Utility		Utility		Other		Total

Revenues from:
External customers		$	588,122	$	332,443	$	6,194	$	926,759
Internal customers			189		807		—		996

	Total revenue		588,311		333,250		6,194		927,755
Segment net income		$	24,839	$	17,817	$	1,795	$	44,451
March 31, 2002
Revenues from:
External customers		$	540,819	$	187,213	$	6,733	$	734,765
Internal customers			163		323		—		486

	Total revenue		540,982		187,536		6,733		735,251
Segment net income		$	20,717	$	10,625	$	1,691	$	33,033

NSP-Wisconsin


				Natural
Three months ended		Electric		Gas		All			Consolidated
March 31, 2003		Utility		Utility		Other			Total

Revenues from:
External customers		$	120,487	$	63,866	$	87		$	184,440
Internal customers			39		567		—			606

	Total revenue		120,526		64,433		87			185,046
Segment net income		$	15,366	$	4,489	$	(1	)	$	19,854
March 31, 2002
Revenues from:
External customers		$	116,877	$	40,299	$	86		$	157,262
Internal customers			45		95		—			140

	Total revenue		116,922		40,394		86			157,402
Segment net income		$	14,262	$	3,905	$	(216	)	$	17,951

PSCo


				Natural
Three months ended		Electric		Gas		All		Consolidated
March 31, 2003		Utility		Utility		Other		Total

Revenues from:
External customers		$	492,370	$	256,665	$	6,648	$	755,683
Internal customers			68		12		—		80

	Total revenue		492,438		256,677		6,648		755,763
Segment net income		$	35,714	$	32,666	$	1,707	$	70,087
March 31, 2002
Revenues from:
External customers		$	433,999	$	316,851	$	7,765	$	758,615
Internal customers			51		14		—		65

	Total revenue		434,050		316,865		7,765		758,680
Segment net income		$	31,820	$	30,900	$	3,971	$	66,691

In 2003, the process to allocate common costs of the electric and gas utility segments was revised. Segment results for 2002 have been restated to reflect the revised cost allocation process.

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 $244.6 million and $211.7 million for the three months ended March 31, 2003 and 2002, respectively.

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

NSP-Minnesota

The components of total comprehensive income are shown below:


		Three months ended
(Millions of dollars)		March 31

		2003		2002

Net income		$	44.5	$	33.0
Other comprehensive loss:
	After-tax net unrealized (losses) gains related to derivatives accounted for as hedges (see Note 6)		—		(0.1	)
	After-tax net realized (gains) losses on derivative transactions reclassified into earnings (see Note 6)		—		(0.2	)

Other comprehensive loss			—		(0.3	)

Comprehensive income		$	44.5	$	32.7

The accumulated comprehensive income in stockholder’s equity at March 31, 2003 and 2002, relates to valuation adjustments on NSP-Minnesota’s derivative financial instruments and hedging activities and the mark-to-market components of NSP-Minnesota’s marketable securities.

NSP-Wisconsin

For NSP-Wisconsin, comprehensive income equals net income for the quarters ended March 31, 2003 and 2002.

PSCo

The components of total comprehensive income are shown below:


		Three months ended
(Millions of dollars)		March 31

		2003		2002

Net income		$	70.1	$	66.7
Other comprehensive income:
	After-tax net unrealized gains (losses) related to derivatives accounted for as hedges (see Note 6)		1.3		8.7
	After-tax net realized losses (gains) on derivative transactions reclassified into earnings (see Note 6)		0.4		(0.8	)

Other comprehensive income			1.7		7.9

Comprehensive income		$	71.8	$	74.6

The accumulated comprehensive income in stockholder’s equity at March 31, 2003 and 2002, relates to valuation adjustments on PSCo’s derivative financial instruments and hedging activities, the mark-to-market component of PSCo’s marketable securities and its minimum pension liability.

SPS

The components of total comprehensive income are shown below:


		Three months ended
(Millions of dollars)		March 31

		2003		2002

Net income		$	10.1	$	14.7
Other comprehensive income (loss):
	After-tax net unrealized gains (losses) related to derivatives accounted for as hedges (see Note 6)		0.4		(0.3	)
	After-tax net realized losses (gains) on derivative transactions reclassified into earnings (see Note 6)		—		0.2

Other comprehensive income (loss)			0.4		(0.1	)

Comprehensive income		$	10.5	$	14.6

The accumulated comprehensive income in stockholder’s equity at March 31, 2003 and 2002, relates to valuation adjustments on SPS’ derivative financial instruments and hedging activities.

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

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

• actions of credit rating agencies;

• business conditions in the energy industry;

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

• unusual weather;

• state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural 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 March 31, 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, 2002. Commodity price and interest rate risks for the Utility Subsidiaries of Xcel Energy are mitigated in most jurisdictions due to cost-based rate regulation. There have been no material changes in the market risk exposures that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2002.

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

NSP-MINNESOTA MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

NSP-Minnesota’s net income was approximately $44.5 million for the first three months of 2003, compared with approximately $33.0 million for the first three months of 2002.

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 significantly affect electric utility margin.

NSP-Minnesota has two distinct forms of wholesale sales: short-term wholesale and electric commodity trading. Short-term wholesale refers to electric sales for resale (excluding sales to retail and municipal customers), which are associated with energy produced from NSP-Minnesota’s generation assets or energy and capacity purchased to serve native load. Electric commodity trading refers to the sales for resale activity of purchasing and reselling electric energy to the wholesale market. Margins from electric commodity trading activity, conducted at NSP-Minnesota, is partially redistributed to PSCo and SPS pursuant to the Joint Operating Agreement (JOA) approved by the FERC. Trading margins are reported net of related costs in the Consolidated Statements of Income. The following table details electric utility, short-term wholesale and electric commodity trading revenue and margin:


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

Three months ended 3/31/2003
Electric utility revenue	$	548		$	39		$	—		$	587
Electric fuel and purchased power		(193	)		(16	)		—			(209	)
Electric trading revenue		—			—			15			15
Electric trading costs		—			—			(14	)		(14	)

Gross margin before operating expenses	$	355		$	23		$	1		$	379

Margin as a percentage of revenue		64.8	%		59.0	%		6.7	%		63.0	%
Three months ended 3/31/2002
Electric utility revenue	$	514		$	24		$	—		$	538
Electric fuel and purchased power		(166	)		(18	)		—			(184	)
Electric trading revenue		—			—			13			13
Electric trading costs		—			—			(10	)		(10	)

Gross margin before operating expenses	$	348		$	6		$	3		$	357

Margin as a percentage of revenue		67.7	%		25.0	%		23.1	%		64.8	%

Base electric utility revenues increased by $34 million, or 6.6 percent, in the first three months of 2003, compared with the same period in 2002. Base electric utility margins increased by $7 million, or 2.0 percent in the first three months of 2003 when compared with the same period in 2002. The increase in revenues and margins reflects sales growth and favorable weather in 2003. The revenue increase was also attributable to higher purchased power costs recovered through electric rates.

Short-term wholesale margins increased in the first three months of 2003, compared with the first three months of 2002, primarily due to more favorable prices on electric sales to other utilities.

Natural 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 sales to retail customers, fluctuations in the cost of gas have little effect on gas margin.


	Three months ended March 31

(Millions of dollars)	2003			2002

Natural gas revenue	$	333		$	188
Cost of natural gas sold and transported		(269	)		(128	)

Natural gas utility margin	$	64		$	60

Natural gas revenue increased by approximately $145 million, or 77.1 percent, in the first three months of 2003, primarily due to increases in the cost of natural gas, which are largely passed on to customers through various rate adjustment clauses. Natural gas margin for the first three months of 2003 increased by $4 million, or 6.7 percent, compared with the first three months of 2002, primarily due to sales growth and favorable weather in 2003, partially offset by lower margins from transportation services.

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expense decreased by approximately $10.3 million, or 4.6 percent, for the first three months of 2003, compared with the first three months of 2002. The decreased costs in the first quarter reflect an unfavorable 2002 Conservation Improvement Program adjustment and the timing of plant outage costs.

Depreciation and Amortization Expense increased by approximately $5.8 million, or 6.8 percent, for the first three months of 2003, compared with the first three months of 2002, primarily due to capital additions to utility plant.

As discussed in Note 2 to the Financial Statements, in the first quarter of 2002, pretax special charges of $4.3 million were expensed for the costs of staff consolidations. The charges related to 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 $5.6 million, due primarily to a gain on the sale of property by a subsidiary of NSP-Minnesota, First Midwest Auto Park, in March 2002.

Interest charges and financing costs increased by approximately $14.4 million, or 81.9 percent, for the first three months of 2003, compared with the first three months of 2002. The increase is due to the issuance of long-term debt in July and August of 2002, including issues at higher interest rates.

NSP-WISCONSIN MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

NSP-Wisconsin’s net income was $19.9 million for the first three months of 2003, compared with $18.0 million for the first three months of 2002.

Electric Utility Margins

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


		Three months ended March 31,

(Millions of dollars)		2003			2002

Total electric utility revenue		$	121		$	117
Electric fuel and purchased power			(56	)		(55	)

	Total electric utility margin	$	65		$	62

Electric utility margin increased by approximately $3 million, or 4.3 percent, in the first three months of 2003, compared with the first three months of 2002, primarily due to sales growth, more favorable weather conditions in 2003, and higher

billings to NSP-Minnesota for energy delivered and cost allocations. Partially offsetting the revenue increases were lower fuel cost recoveries through rates in the first three months of 2003, compared to the first three months of 2002.

Natural Gas Utility Margins

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


	Three months ended March 31,

(Millions of dollars)	2003			2002

Natural gas revenue	$	64		$	40
Cost of natural gas purchased and transported		(51	)		(29	)

Natural gas margin	$	13		$	11

Natural gas revenue increased by approximately $24 million, or 59.5 percent, in the first three months of 2003 compared with the first three months of 2002, primarily due to significant increases in the cost of natural gas, which is largely recovered through various purchased natural gas cost recovery mechanisms. Natural gas margin increased by $2 million, or 23.4 percent, in the first three months of 2003 due to sales growth and more favorable weather conditions in 2003.

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expense for the first three months of 2003 increased $0.9 million, or 3.6 percent, compared with the first three months of 2002, primarily due to higher benefit costs and a favorable conservation cost adjustment in 2002.

Depreciation and Amortization Expense increased by approximately $0.6 million, or 5.4 percent, in the first three months of 2003, compared with the first three months of 2002, primarily due to capital additions to utility plant.

As discussed in Note 2 to the Financial Statements, in the first quarter of 2002, pretax special charges of $0.5 million were expensed for the costs of staff consolidations. The charges related to severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy.

Other Income decreased $0.5 million in the first three months of 2003 compared with the first three months of 2002, primarily due to lower interest income from economic development loans.

PSCo’S MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

PSCo’s net income was approximately $70.1 million for the first three months of 2003, compared with approximately $66.7 million for the first three months of 2002.

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. The retail fuel clause cost recovery mechanism in Colorado has changed from 2002 to 2003. For 2002, electric utility margins in Colorado reflect the impact of sharing energy costs and savings relative to a target cost per delivered kilowatt-hour under the retail incentive cost adjustment (ICA) mechanism. For 2003, PSCo will be able to collect 100 percent of its retail electric fuel and purchased energy expense through a new interim adjustment clause (IAC). The fuel cost mechanisms do not allow for complete recovery of all variable production expenses, and higher costs can adversely affect earnings. In addition to the ICA and the IAC, PSCo has other adjustment clauses that allow certain costs to be passed through to retail customers.

Some electric commodity trading activity, initially recorded at PSCo, is partially redistributed to NSP-Minnesota 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. Trading margins reflect the impact of sharing certain trading margins with Colorado retail customers. The following table details electric utility, short-term wholesale and electric trading revenue and margin.


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

Three months ended March 31, 2003
Electric utility revenue	$	474		$	20		$	—		$	494
Electric fuel and purchased power		(234	)		(22	)		—			(256	)
Electric trading revenue		—			—			43			43
Electric trading costs		—			—			(45	)		(45	)

Gross margin before operating expenses	$	240		$	(2	)	$	(2	)	$	236

Margin as a percentage of revenue		50.6	%		(10.0	)%		(4.7	)%		43.9	%

Three months ended March 31, 2002
Electric utility revenue	$	422		$	16		$	—		$	438
Electric fuel and purchased power		(192	)		(17	)		—			(209	)
Electric trading revenue		—			—			300			300
Electric trading costs		—			—			(304	)		(304	)

Gross margin before operating expenses	$	230		$	(1	)	$	(4	)	$	225

Margin as a percentage of revenue		54.5	%		(6.3	)%		(1.3	)%		30.5	%

Base electric revenues increased approximately $52 million, or 12.3 percent, in the first three months of 2003 compared with 2002 due to higher cost recovery levels under the IAC in 2003 and to sales growth.

Base electric utility margin increased by approximately $10 million, or 4.3 percent, in the first three months of 2003, compared with the first three months of 2002. The higher base electric margins reflect sales growth and the implementation of an air-quality improvement rider for the recovery of investments and related costs to improve air quality in Colorado. Higher demand costs partially offset the increase in the quarter.

Natural Gas Utility Margins

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


	Three Months ended March 31,

(Millions of dollars)	2003			2002

Natural gas utility revenue	$	257		$	317
Cost of natural gas sold and transported		(155	)		(211	)

Natural gas utility margin	$	102		$	106

Natural gas revenue for the first three months of 2003 decreased by approximately $60 million, or 18.9 percent, compared with the first three months of 2002, largely due to lower revenues recognized for cost recovery levels approved under the GCA. Natural gas margin for the first three months of 2003 decreased by approximately $4 million, or 3.8 percent, compared with the first three months of 2002, primarily due to warmer winter weather, which is less favorable for natural gas sales. GCA recovery was lower in 2003 despite higher natural gas costs in the first quarter compared to 2002. Costs not recovered currently are deferred to future periods when GCA recovery is provided.

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expense decreased approximately $2.5 million, or 2.1 percent, for the first three months of 2003 compared with the first three months of 2002. The decrease is largely due to a reduced bad debt expense, lower non-regulated product costs and the timing of expenditures.

Depreciation and Amortization Expense decreased by approximately $5.9 million, or 9.2 percent, for the first three months of 2003 compared with the first three months of 2002, primarily due to decreased amortization of software and to depreciation of Arapahoe plant units 1 and 2 ending at Dec. 31, 2002.

Interest expense increased by approximately $8.3 million, or 29.9 percent, for the first three months of 2003 compared with the first three months of 2002. Increased interest costs reflect higher debt levels in 2003 and higher interest rates on recent debt issues.

SPS’ MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

SPS’ net income was approximately $10.1 million for the first three months of 2003, compared with approximately $14.7 million for the first three months of 2002.

Electric Utility Margins

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


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

3 months ended 3/31/2003
Electric utility revenue	$	242		$	3		$	245
Electric fuel and purchased power		(138	)		(2	)		(140	)

Gross margin before operating expenses	$	104		$	1		$	105

Margin as a percentage of revenue		43.0	%		33.3	%		42.9	%

3 months ended 3/31/2002
Electric utility revenue	$	210		$	2		$	212
Electric fuel and purchased power		(96	)		(2	)		(98	)

Gross margin before operating expenses	$	114		$	—		$	114

Margin as a percentage of revenue		54.3	%		—			53.8	%

Base electric revenue increased by approximately $32 million, or 15.2 percent, for the first three months of 2003, compared with the first three months of 2002. Base electric margin decreased by approximately $10 million, or 8.8 percent, for the first three months of 2003, compared with the first three months of 2002. Base electric revenues increased largely due to higher fuel and purchased power costs recovered through electric rates, partially offset by lower sharing of commodity trading margins with PSCo and NSP-Minnesota through the JOA approved by the FERC. The decrease in base electric margin was primarily due to the effects of lower capacity margins, the settlement of the Texas fuel proceeding, and lower revenues shared through the JOA.

Non-Fuel Operating Expense and Other Costs

Other Operation and Maintenance Expense increased by approximately $3.3 million, or 8.4 percent, for the first three months of 2003, compared with the first three months of 2002. The change is largely due to an unfavorable inventory adjustment in 2003.

As discussed in Note 2 to the Financial Statements, in late 2001 SPS filed an application requesting a rate rider to recover 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 in 2002, which are reported as special charges.

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 Utility Subsidiary 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 Utility Subsidiary 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 3 and 4 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’ 2002 Form 10-K for a description of certain legal proceedings presently pending. There are no new significant cases to report against the Utility Subsidiaries of Xcel Energy and there have been no notable changes in the previously reported proceedings, except as set forth below.

NSP-Minnesota

Under a 1996 Data Services Agreement (DSA), SchlumberSema, Inc. (SLB) provides automated meter reading, distribution automation, and other data services to NSP-Minnesota. In September 2002, NSP-Minnesota issued written notice that SLB had committed events of default under the DSA, including SLB's nonpayment of approximately $7.4 million for distribution automation assets. In November 2002, SLB demanded arbitration before the American Arbitration Association and asserted various claims against NSP-Minnesota totaling $24 million for NSP's alleged breach of an expansion contract and a meter purchasing contract. On April 9, 2003, the parties attempted to mediate their dispute. The mediation was unsuccessful. On April 16, 2003 SchlumberSema, Inc. filed a motion in the U.S. Bankruptcy Court in Delaware for an Order that "any claim against SchlumberSema, Inc., arising from the alleged failure to sign the DA Transfer Agreement was cured, released, waived and/or barred by this court's Order of May 4, 2000 approving the sale of CellNet Data Systems, Inc.'s assets to SLB". NSP-Minnesota will vigorously oppose this motion.

NSP-Wisconsin

On Sept. 25, 2000, NSP-Wisconsin was served with a complaint in Eau Claire County Circuit Court, Wisconsin, on behalf of Claron and Janice Stubrud. The complaint alleged that stray voltage from NSP-Wisconsin’s system harmed their dairy herd resulting in lost milk production, lost profits and income, property damage, and injury to their dairy herd. The complaint also alleged that NSP-Wisconsin acted willfully and wantonly, entitling plaintiffs to treble damages. The plaintiffs alleged farm damages of approximately $3.8 million, $2.7 million of which represents prejudgment interest. On March 28, 2003, the trial court granted partial summary judgment to NSP-Wisconsin and dismissed plaintiffs’ claims for strict products liability, trespass, treble damages, and prejudgment interest. Plaintiffs’ negligence and nuisance claims will proceed to trial in Eau Claire County in November 2003.

SPS

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

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

The following Exhibits are filed with this report:


4.01		Supplemental Indenture dated April 1, 2003, between PSCo and U.S. Bank Trust National Association, as trustee, creating $600,000,000 principal amount of First Mortgage Bonds, Collateral Series J, due 2012.

4.02		Supplemental Indenture dated April 1, 2003, between PSCo and U.S. Bank Trust National Association, as trustee, creating $600,000,000 principal amount of First Collateral Trust Bonds, Series No. 11, due 2012.

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 March 31, 2003, or between March 31, 2003, and the date of this report:

NSP-Minnesota and PSCo

March 7, 2003, (filed March 10, 2003) Item 5 and 7. Other Events and Exhibits. Re: PSCo Offering Memorandum for potential purchasers (private placement) of debt securities.

March 18, 2003, (filed March 25, 2003) Item 5 and 7. Other Events and Exhibits. Re: NSP-MN System Participation Power Sale Agreement.

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 May 15, 2003.


	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: May 15, 2003


	/s/ WAYNE H. BRUNETTI Wayne H. Brunetti Chairman, President and Chief Executive Officer

I, Richard C. Kelly, certify that:


	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

Date: May 15, 2003


		/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, Michael L. Swenson, certify that:

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

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):

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: May 15, 2003


		/s/ MICHAEL L. SWENSON Michael L. Swenson President and Chief Executive Officer

I, Richard C. Kelly, certify that:

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

Date: May 15, 2003


		/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:

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

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

Date: May 15, 2003


		/s/ WAYNE H. BRUNETTI Wayne H. Brunetti Chairman, President and Chief Executive Officer

I, Richard C. Kelly, certify that:

Date: May 15, 2003


		/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:

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

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

Date: May 15, 2003


	/s/ GARY L. GIBSON Gary L. Gibson President and Chairman

I, Richard C. Kelly, certify that:


	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

Date: May 15, 2003


		/s/ RICHARD C. KELLY Richard C. Kelly Vice President and Chief Financial Officer

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

	•		an interim adjustment clause (IAC) that recovers 100 percent of prudently incurred 2003 electric fuel and purchased energy expense above the expense recovered through electric base rates during 2003. This clause is projected to recover energy costs totaling approximately $216 million in 2003. The IAC originally went into effect on Jan. 1, 2003. The IAC rate was increased on May 1, 2003 by $93 million to recover the total anticipated energy costs for 2003;

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

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

•		general economic conditions, including their impact on capital expenditures and the ability of Xcel Energy’s Utility Subsidiaries to obtain financing on favorable terms;

•		actions of credit rating agencies;

•		business conditions in the energy industry;

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

•		unusual weather;

•		state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural 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 March 31, 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: