10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)
þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended March 31, 2002
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from           to

	Exact name of registrant as specified in its charter, State or other
Commission	jurisdiction of incorporation or organization, Address of principal	IRS Employer
File Number	executive offices and Registrant’s Telephone Number, including area code	Identification No.
000-31709	NORTHERN STATES POWER COMPANY (a Minnesota Corporation) 414 Nicollet Mall, Minneapolis, Minn. 55401 Telephone (612) 330-5500		41-1967505
001-3140	NORTHERN STATES POWER COMPANY (a Wisconsin Corporation) 1414 W. Hamilton Ave., Eau Claire, Wis. 54701 Telephone (715) 839-2621		39-0508315
001-3280	PUBLIC SERVICE COMPANY OF COLORADO (a Colorado Corporation) 1225 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 þ          No o

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

      Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. All outstanding common stock is owned beneficially and of record by Xcel Energy Inc., a Minnesota corporation. Shares outstanding at April 30, 2002:

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

TABLE OF CONTENTS

EX-99.01 Statement pursuant to Private Securities

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements	2
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	34
Item 6.	Exhibits and Reports on Form 8-K	34

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

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

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

1

PART 1.     FINANCIAL INFORMATION

Item 1.     Consolidated Financial Statements

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

			Three Months Ended
			March 31
			2002		2001
			(Unaudited)
			(Thousands of Dollars)
Operating revenues:
	Electric utility		$	537,882	$	614,115
	Gas utility			187,536		352,738
	Electric trading			13,068		—
	Other			6,733		15,220
		Total operating revenues		745,219		982,073
Operating expenses:
	Electric fuel and purchased power			184,445		243,047
	Cost of gas sold and transported			128,488		288,392
	Electric trading costs			9,968		—
	Operating and maintenance expenses			221,874		215,777
	Depreciation and amortization			85,432		83,179
	Taxes (other than income taxes)			43,318		51,848
	Special charges (see Note 2)			4,324		—
		Total operating expenses		677,849		882,243
Operating income				67,370		99,830
Other income (expense) — net				8,664		(229	)
Interest charges and financing costs:
	Interest charges — net of amounts capitalized			17,575		25,114
	Distributions on redeemable preferred securities of subsidiary trust			3,938		3,938
		Total interest charges and financing costs		21,513		29,052
Income before income taxes				54,521		70,549
Income taxes				21,488		28,377
Net income			$	33,033	$	42,172

See Notes to Consolidated Financial Statements.

2

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF CASH FLOWS

				Three Months Ended
				March 31
				2002			2001
				(Unaudited)
				(Thousands of Dollars)
Operating activities:
	Net income			$	33,033		$	42,172
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			87,361			86,727
		Nuclear fuel amortization			12,037			9,441
		Deferred income taxes			(20,277	)		(2,628	)
		Amortization of investment tax credits			(2,212	)		(2,052	)
		Allowance for equity funds used during construction			(1,488	)		423
		Conservation incentive accrual adjustments			(2,864	)		—
		Gain on sale of property			(6,785	)		—
		Change in accounts receivable			(18,015	)		(2,449	)
		Change in inventories			10,500			14,536
		Change in other current assets			15,946			50,350
		Change in accounts payable			(14,261	)		(79,218	)
		Change in other current liabilities			56,573			24,896
		Change in other assets and liabilities			13,030			24,413
			Net cash provided by operating activities		162,578			166,611
Investing activities:
	Utility capital/ construction expenditures				(88,010	)		(74,788	)
	Proceeds from sale of property				11,152			—
	Allowance for equity funds used during construction				1,488			(423	)
	Investments in external decommissioning fund				(14,259	)		(14,426	)
	Other investments — net				(963	)		(9,766	)
		Net cash used in investing activities			(90,592	)		(99,403	)
Financing activities:
	Short-term borrowings — net				(5,142	)		(128,002	)
	Repayment of long-term debt, including reacquisition premiums				(278	)		(364	)
	Capital contributions from parent				—			175,000
	Dividends paid to parent				(44,332	)		(37,606	)
		Net cash (used in) provided by financing activities			(49,752	)		9,028
Net increase in cash and cash equivalents					22,234			76,236
Cash and cash equivalents at beginning of year					17,169			11,926
Cash and cash equivalents at end of year				$	39,403		$	88,162

See Notes to Consolidated Financial Statements.

3

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

				March 31,			Dec. 31,
				2002			2001
				(Unaudited)
				(Thousands of Dollars)
ASSETS
Current assets:
	Cash and cash equivalents			$	39,403		$	17,169
	Accounts receivable — net of allowance for bad debts: $5,259 and $5,452, respectively				265,526			227,007
	Accounts receivable from affiliates				10,908			31,528
	Accrued unbilled revenues				107,732			125,770
	Materials and supplies inventories				108,023			103,934
	Fuel inventory				34,374			31,945
	Gas inventory				8,104			25,122
	Prepayments and other				52,794			48,489
			Total current assets		626,864			610,964
Property, plant and equipment, at cost:
	Electric utility plant				6,606,244			6,582,337
	Gas utility plant				696,104			695,338
	Construction work in progress				340,157			316,468
	Other				358,530			368,513
			Total property, plant and equipment		8,001,035			7,962,656
	Less accumulated depreciation				(4,388,834	)		(4,310,214	)
	Nuclear fuel — net of accumulated amortization of $1,021,892 and $1,009,855, respectively				119,189			96,315
			Net property, plant and equipment		3,731,390			3,748,757
Other assets:
	Nuclear decommissioning fund investments				610,167			596,113
	Other investments				23,742			22,542
	Regulatory assets				210,395			226,088
	Prepaid pension asset				207,553			188,287
	Other				72,746			64,278
		Total other assets			1,124,603			1,097,308
		Total assets		$	5,482,857		$	5,457,029
LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt			$	152,428		$	153,134
	Short-term debt				376,041			381,184
	Accounts payable				196,668			235,930
	Accounts payable to affiliates				67,573			42,550
	Taxes accrued				232,062			168,491
	Dividends payable to parent				48,318			44,332
	Other				61,395			76,004
			Total current liabilities		1,134,485			1,101,625
Deferred credits and other liabilities:
	Deferred income taxes				686,985			697,605
	Deferred investment tax credits				80,387			82,598
	Regulatory liabilities				486,065			468,051
	Benefit obligations and other				140,414			133,771
			Total deferred credits and other liabilities		1,393,851			1,382,025
Long-term debt					1,034,478			1,039,220
Mandatorily redeemable preferred securities of subsidiary trust					200,000			200,000
Common stock — authorized 5,000,000 shares of $0.01 par value, outstanding 1,000,000 shares					10			10
Premium on common stock					762,155			762,155
Retained earnings					975,150			990,435
Leveraged ESOP					(17,086	)		(18,564	)
Accumulated other comprehensive income					(186	)		123
	Total common stockholder’s equity				1,720,043			1,734,159
Commitments and contingencies (See Note 5)
			Total liabilities and equity	$	5,482,857		$	5,457,029

See Notes to Consolidated Financial Statements.

4

NSP-WISCONSIN

STATEMENTS OF INCOME

			Three Months Ended
			March 31
			2002		2001
			(Unaudited)
			(Thousands of Dollars)
Operating revenues:
	Electric utility		$	116,922	$	113,892
	Gas utility			40,394		69,550
	Other			86		125
		Total operating revenues		157,402		183,567
Operating expenses:
	Electric fuel and purchased power			54,531		60,523
	Cost of gas sold and transported			29,234		57,032
	Other operating and maintenance expenses			23,588		25,142
	Depreciation and amortization			10,755		10,243
	Taxes (other than income taxes)			4,100		4,062
	Special charges (see Note 2)			512		—
		Total operating expenses		122,720		157,002
Operating income				34,682		26,565
Other income (expense) — net				822		294
Interest charges				5,833		5,539
Income before income taxes				29,671		21,320
Income taxes				11,720		8,228
Net income			$	17,951	$	13,092

See Notes to Financial Statements.

5

NSP-WISCONSIN

STATEMENTS OF CASH FLOWS

				Three Months Ended
				March 31
				2002			2001
				(Unaudited)
				(Thousands of Dollars)
Operating activities:
	Net income			$	17,951		$	13,092
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			11,060			10,495
		Deferred income taxes			155			806
		Amortization of investment tax credits			(202	)		(205	)
		Allowance for equity funds used during construction			(184	)		(291	)
		Undistributed equity in earnings of unconsolidated affiliates			(62	)		(60	)
		Change in accounts receivable			(15,218	)		1,507
		Change in inventories			4,101			3,275
		Change in other current assets			9,469			14,250
		Change in accounts payable			6,800			(27,251	)
		Change in other current liabilities			14,288			7,304
		Change in other assets and liabilities			(3,717	)		(924	)
			Net cash provided by operating activities		44,441			21,998
Investing activities:
	Capital/construction expenditures				(8,037	)		(12,621	)
	Allowance for equity funds used during construction				184			291
	Other investments — net				(81	)		(21	)
			Net cash used in investing activities		(7,934	)		(12,351	)
Financing activities:
	Short-term borrowings from affiliate — net				(25,500	)		(9,500	)
	Dividends paid to parent				(11,006	)		—
			Net cash used in financing activities		(36,506	)		(9,500	)
Net increase in cash and cash equivalents					1			147
Cash and cash equivalents at beginning of period					30			31
Cash and cash equivalents at end of period				$	31		$	178

See Notes to Financial Statements.

6

NSP-WISCONSIN

BALANCE SHEETS

			March 31			Dec. 31
			2002			2001
			(Unaudited)
			(Thousands of Dollars)
ASSETS
Current assets:
	Cash and cash equivalents		$	31		$	30
	Accounts receivable — net of allowance for bad debts of $994 and $969, respectively			46,612			31,870
	Accounts receivable from affiliates			3,525			3,006
	Accrued unbilled revenues			17,464			20,596
	Materials and supplies inventories			5,567			5,885
	Fuel inventory			5,152			5,854
	Gas inventory			230			3,311
	Prepaid taxes			10,023			13,157
	Prepayments and other			746			3,949
		Total current assets		89,350			87,658
Property, plant and equipment, at cost:
	Electric utility plant			1,140,157			1,132,114
	Gas utility plant			129,465			127,635
	Other and construction work in progress			112,080			115,435
		Total property, plant and equipment		1,381,702			1,375,184
	Less accumulated depreciation			(564,141	)		(553,467	)
		Net property, plant and equipment		817,561			821,717
Other assets:
	Other investments			9,969			9,824
	Regulatory assets			36,919			37,123
	Prepaid pension assets			30,944			28,563
	Other			8,184			7,373
		Total other assets		86,016			82,883
		Total assets	$	992,927		$	992,258
LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	34		$	34
	Short-term debt — notes payable to affiliate			8,800			34,300
	Accounts payable			13,977			14,482
	Accounts payable to affiliates			5,881			—
	Dividends payable to parent			11,411			10,988
	Other			35,446			22,515
		Total current liabilities		75,549			82,319
Deferred credits and other liabilities:
	Deferred income taxes			121,456			119,895
	Deferred investment tax credits			15,426			15,628
	Regulatory liabilities			16,064			16,891
	Benefit obligations and other			35,270			34,925
		Total deferred credits and other liabilities		188,216			187,339
Long-term debt				313,076			313,054
Common stock — authorized 1,000,000 shares of $100 par value; outstanding 933,000 shares				93,300			93,300
Premium on common stock				59,771			59,771
Retained earnings				263,015			256,475
		Total common stockholder’s equity		416,086			409,546
Commitments and contingent liabilities (see Note 5)
		Total liabilities and equity	$	992,927		$	992,258

See Notes to Financial Statements.

7

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

			Three Months Ended
			March 31
			2002			2001
			(Unaudited)
			(Thousands of Dollars)
Operating revenues:
	Electric utility		$	437,649		$	589,682
	Electric trading			300,259			298,432
	Gas utility			316,865			547,800
	Steam and other			7,765			12,284
		Total operating revenues		1,062,538			1,448,198
Operating expenses:
	Electric fuel and purchased power			209,168			340,758
	Electric trading costs			303,858			277,142
	Cost of gas sold and transported			210,844			448,296
	Cost of sales — steam and other			1,525			5,475
	Other operating and maintenance expenses			117,318			102,289
	Depreciation and amortization			64,564			58,096
	Taxes (other than income taxes)			22,272			21,849
	Special charges (see Note 2)			131			—
		Total operating expenses		929,680			1,253,905
Operating income				132,858			194,293
Other income (expense) — net				(1,092	)		9,729
Interest charges and financing costs:
	Interest charges — net of amount capitalized			27,655			30,165
	Distributions on redeemable preferred securities of subsidiary trust			3,800			3,800
		Total interest charges and financing costs		31,455			33,965
Income before income taxes				100,311			170,057
Income taxes				33,620			62,667
Net income			$	66,691		$	107,390

See Notes to Consolidated Financial Statements.

8

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

				Three Months Ended
				March 31
				2002			2001
				(Unaudited)
				(Thousands of Dollars)
Operating activities:
	Net income			$	66,691		$	107,390
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			65,434			59,956
		Deferred income taxes			11,395			(380	)
		Amortization of investment tax credits			(1,022	)		(1,030	)
		Allowance for equity funds used during construction			2			(184	)
		Unrealized gain on derivative financial instruments			(76	)		(362	)
		Change in accounts receivable			(44,791	)		(39,233	)
		Change in inventories			38,459			26,652
		Change in other current assets			(27,846	)		116,480
		Change in accounts payable			(55,463	)		(271,535	)
		Change in other current liabilities			83,789			162,788
		Change in other assets and liabilities			(3,624	)		8,052
			Net cash provided by operating activities		132,948			168,594
Investing activities:
	Capital/construction expenditures				(86,162	)		(69,724	)
	Proceeds from disposition of property, plant and equipment				6,363			2,709
	Allowance for equity funds used during construction				(2	)		184
	Other investments — net				1,769			3,245
			Net cash used in investing activities		(78,032	)		(63,586	)
Financing activities:
	Short-term borrowings — net				(46,159	)		94,625
	Proceeds from issuance of long-term debt				—			100,180
	Repayment of long-term debt, including reacquisition premiums				(568	)		(239,876	)
	Capital contributions from parent				50,000			—
	Dividends paid to parent				(53,387	)		(57,615	)
			Net cash used in financing activities		(50,114	)		(102,686	)
	Net increase in cash and cash equivalents				4,802			2,322
	Cash and cash equivalents at beginning of period				22,666			15,696
	Cash and cash equivalents at end of period			$	27,468		$	18,018

See Notes to Consolidated Financial Statements.

9

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

			March 31 2002			Dec. 31 2001
			(Unaudited)
			(Thousands of Dollars)
ASSETS
Current assets:
	Cash and cash equivalents		$	27,468		$	22,666
	Accounts receivable — net of allowance for bad debts of $15,481 and $14,510, respectively			232,895			209,913
	Accounts receivable from affiliates			21,809			—
	Accrued unbilled revenues			245,465			269,167
	Recoverable purchased gas and electric energy costs			59,208			16,763
	Materials and supplies inventories at average cost			40,178			40,893
	Fuel inventory at average cost			23,244			22,135
	Gas inventory — replacement cost in excess of LIFO: $807 and $11,331, respectively			40,652			79,505
	Derivative instruments valuation — at market			15,295			3,855
	Prepayments and other			55,952			56,001
		Total current assets		762,166			720,898
Property, plant and equipment, at cost:
	Electric utility			5,266,776			5,253,693
	Gas utility			1,429,229			1,416,730
	Other and construction work in progress			905,261			859,800
		Total property, plant and equipment		7,601,266			7,530,223
	Less: accumulated depreciation			(2,797,825	)		(2,746,687	)
		Net property, plant and equipment		4,803,441			4,783,536
Other assets:
	Other investments			8,343			10,112
	Regulatory assets			188,633			192,841
	Prepaid pension asset			64,071			60,797
	Other			39,191			72,694
		Total other assets		300,238			336,444
		Total assets	$	5,865,845		$	5,840,878

10

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS — (Continued)

			March 31 2002		Dec. 31 2001
			(Unaudited)
			(Thousands of Dollars)
LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	17,118	$	17,174
	Short-term debt			545,218		591,377
	Accounts payable			322,380		359,406
	Accounts payable to affiliates			41,714		60,151
	Taxes accrued			106,175		60,780
	Dividends payable to parent			55,449		53,387
	Derivative instruments valuation — at market			5,318		50,385
	Other			179,639		141,245
		Total current liabilities		1,273,011		1,333,905
Deferred credits and other liabilities:
	Deferred income taxes			568,741		564,268
	Deferred investment tax credits			78,630		79,652
	Regulatory liabilities			47,825		49,048
	Other deferred credits			14,063		12,435
	Customer advances for construction			87,994		85,582
	Benefit obligations and other			77,645		66,835
		Total deferred credits and other liabilities		874,898		857,820
Long-term debt				1,464,710		1,465,055
Mandatorily redeemable preferred securities of subsidiary trust				194,000		194,000
Common stock — authorized 100 shares of $0.01 par value, outstanding 100 shares				—		—
Premium on common stock				1,640,084		1,590,084
Retained earnings				415,589		404,347
Accumulated other comprehensive income				3,553		(4,333	)
		Total common stockholder’s equity		2,059,226		1,990,098
Commitments and contingent liabilities (see Note 5)
		Total liabilities and equity	$	5,865,845	$	5,840,878

See Notes to Consolidated Financial Statements.

11

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF INCOME

			Three Months Ended
			March 31
			2002		2001
			(Unaudited)
			(Thousands of Dollars)
Operating revenues			$	211,692	$	329,273
Operating expenses:
	Electric fuel and purchased power			97,976		204,336
	Other operating and maintenance expenses			39,516		36,046
	Depreciation and amortization			22,004		20,269
	Taxes (other than income taxes)			11,758		14,909
	Special charges (see Note 2)			5,321		—
		Total operating expenses		176,575		275,560
Operating income				35,117		53,713
Other income (expense) — net				1,848		2,243
Interest charges and financing costs:
	Interest charges — net of amounts capitalized			11,392		12,080
	Distributions on redeemable preferred securities of subsidiary trust			1,963		1,963
		Total interest charges and financing costs		13,355		14,043
Income before income taxes				23,610		41,913
Income taxes				8,862		15,864
Net income			$	14,748	$	26,049

See Notes to Financial Statements.

12

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CASH FLOWS

				Three Months Ended
				March 31
				2002			2001
				(Unaudited)
				(Thousands of Dollars)
Operating activities:
	Net income			$	14,748		$	26,049
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			23,826			21,355
		Deferred income taxes			4,092			18,632
		Amortization of investment tax credits			(62	)		(63	)
		Change in accounts receivable			(9,178	)		18,831
		Change in inventories			(1,213	)		2,725
		Change in other current assets			40,570			(43,387	)
		Change in accounts payable			7,980			(62,678	)
		Change in other current liabilities			(41,852	)		32,216
		Change in other assets and liabilities			(5,422	)		(343	)
			Net cash provided by operating activities		33,489			13,337
Investing activities:
	Capital/construction expenditures				(6,478	)		(27,810	)
	Costs/proceeds from disposition of property, plant and equipment				—			2,193
	Other investments — net				(1,073	)		456
			Net cash used in investing activities		(7,551	)		(25,161	)
Financing activities:
	Short-term borrowings — net				—			54,546
	Repayment of long-term debt, including reacquisition premiums				—			168
	Dividends paid to parent				(60,969	)		(22,354	)
			Net cash (used in) provided by financing activities		(60,969	)		32,360
	Net (decrease) increase in cash and cash equivalents				(35,031	)		20,536
	Cash and cash equivalents at beginning of period				65,499			10,826
	Cash and cash equivalents at end of period			$	30,468		$	31,362

See Notes to Financial Statements.

13

SOUTHWESTERN PUBLIC SERVICE CO.

BALANCE SHEETS

			March 31			Dec. 31
			2002			2001
			(Unaudited)
			(Thousands of Dollars)
ASSETS
Current assets:
	Cash and cash equivalents		$	30,468		$	65,499
	Accounts receivable — net of allowance for bad debts of $1,491 and $1,785, respectively			47,428			61,688
	Accounts receivable from affiliates			23,438			—
	Accrued unbilled revenues			42,741			75,924
	Materials and supplies inventories at average cost			13,870			12,588
	Fuel and gas inventories at average cost			1,321			1,390
	Current portion of accumulated deferred income taxes			3,887			10,068
	Prepayments and other			8,964			10,170
		Total current assets		172,117			237,327
Property, plant and equipment, at cost:
	Electric utility			3,056,141			3,056,459
	Other and construction work in progress			62,232			55,436
		Total property, plant and equipment		3,118,373			3,111,895
	Less: accumulated depreciation			(1,296,417	)		(1,275,501	)
		Net property, plant and equipment		1,821,956			1,836,394
Other assets:
	Other investments			12,419			11,345
	Regulatory assets			101,406			96,613
	Prepaid pension asset			87,628			82,503
	Deferred charges and other			31,232			36,598
		Total other assets		232,685			227,059
		Total assets	$	2,226,758		$	2,300,780
LIABILITIES AND EQUITY
Current liabilities:
	Accounts payable		$	69,580		$	72,204
	Accounts payable to affiliates			12,495			1,891
	Taxes accrued			20,365			35,274
	Interest accrued			13,177			9,696
	Dividends payable to parent			—			20,969
	Derivative instruments valuation — at market			1,222			1,131
	Other			37,681			68,105
		Total current liabilities		154,520			209,270
Deferred credits and other liabilities:
	Deferred income taxes			396,824			392,907
	Deferred investment tax credits			4,405			4,467
	Regulatory liabilities			2,451			1,117
	Derivative instruments valuation — at market			5,978			5,809
	Benefit obligations and other			16,451			15,815
		Total deferred credits and other liabilities		426,109			420,115
Long-term debt				725,447			725,375
Mandatorily redeemable preferred securities of subsidiary trust				100,000			100,000
Common stock — authorized 200 shares of $1.00 par value, outstanding 100 shares				—			—
Premium on common stock				405,536			405,536
Retained earnings				419,665			444,917
Accumulated other comprehensive income (loss)				(4,519	)		(4,433	)
		Total common stockholder’s equity		820,682			846,020
Commitments and contingent liabilities (see Note 5)
		Total liabilities and equity	$	2,226,758		$	2,300,780

See Notes to Financial Statements.

14

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, 2002, and Dec. 31, 2001, the results of their operations for the three months ended March 31, 2002 and 2001, and their cash flows for the three months ended March 31, 2002 and 2001. Due to the seasonality of electric and gas sales of Xcel Energy’s Utility Subsidiaries, quarterly results are not necessarily an appropriate base from which to project annual results.

      The accounting policies of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are set forth in Note 1 to the financial statements in their respective Annual Reports on Form 10-K for the year ended Dec. 31, 2001. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K’s.

      We reclassified certain items in the 2001 income statement to conform to the presentation disclosed in the 2001 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 (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

      Intangible Assets — During the first quarter of 2002, the Utility Subsidiaries of Xcel Energy adopted Statement of Financial Accounting Standard (SFAS) No. 142 — “Goodwill and Other Intangible Assets” (SFAS No. 142), which requires new accounting for intangible assets, including goodwill. Intangible assets with finite lives will be amortized over their economic useful lives and periodically reviewed for impairment. Goodwill will no longer be amortized, but would be required to be tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below its carrying value.

      The Utility Subsidiaries of Xcel Energy had no intangible assets which will not be amortized under SFAS No. 142.

      With respect to those intangible assets that will continue to be amortized, aggregate amortization expense recognized in the first quarter of 2002 was approximately $60,000. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $0.24 million. Intangible assets subject to amortization at March 31, 2002, consisting primarily of deferred employment agreement costs, were as follows:

	March 31, 2002				Dec. 31, 2001
	Gross Carrying		Accumulated		Gross Carrying		Accumulated
	Amount		Amortization		Amount		Amortization
	(Thousands of Dollars)
NSP-Minnesota		4,867		385		4,867		324
NSP-Wisconsin		—		—		—		—
PSCo		—		—		—		—
SPS		—		—		—		—

      Asset Valuation — On Jan. 1, 2002, the Utility Subsidiaries adopted SFAS No. 144 — “Accounting for the Impairment or Disposal of Long-Lived Assets,” which supercedes previous guidance for measurement of asset impairments. The Utility Subsidiaries did not recognize any asset impairments as a result of the adoption. The method used in determining fair value was based on a number of valuation techniques, including present value of future cash flows.

15

NOTES TO FINANCIAL STATEMENTS — (Continued)

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, subject to approval by the state regulatory commission. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million.

      2002/2001 Restaffing — During the fourth quarter of 2001, Xcel Energy expensed pretax special charges of $39 million for expected staff consolidation costs for 500 employees. Approximately $36 million of these restaffing costs were allocated to Xcel Energy’s Utility Subsidiaries consistent with service company cost allocation methodologies utilized under the requirements of the PUHCA. In the first quarter of 2002, additional pretax special charges of $9 million were expensed for additional staff consolidations. Approximately $5 million of these restaffing costs were allocated to Xcel Energy’s Utility Subsidiaries. The charges related to severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy. Staff terminations of 564 are now expected to occur. As of March 31, 2002, 551 of these terminations had occurred.

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

				Accrual
		Dec. 31, 2001		Adjustments		Payments			March 31, 2002
		Liability		Expensed		Against Liability			Liability
		(Millions of Dollars)
Employee severance and related costs		$	37	$	9	$	(7	)	$	39
	Total accrued special charges — Xcel Energy	$	37	$	9	$	(7	)	$	39
Special charge activities for Utility Subsidiaries:
NSP-Minnesota		$	5	$	4	$	(2	)	$	7
NSP-Wisconsin			2		1		(2	)		1
PSCo			2		—		—			2
SPS			1		—		—			1

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

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

      Under the proposal, TRANSLink will be responsible for planning, managing and operating both local and regional transmission assets. TRANSLink will also construct and own new transmission system additions. TRANSLink will collect the revenue for the use of Xcel Energy’s transmission assets through a FERC-approved, regulated cost-of-service tariff and will collect its administrative costs through transmission rate

16

NOTES TO FINANCIAL STATEMENTS — (Continued)

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

      In April 2002, the FERC gave conditional approval for the applicants to transfer ownership or operations of their transmission systems to TRANSLink and to form TRANSLink as an independent transmission company operating under the umbrella organization of MISO and a separate RTO in the west (once it is formed) for Public Service Company of Colorado (PSCo) assets. The FERC conditioned TRANSLink’s approval on the resubmission of its tariff as a separate schedule to be administered by the MISO. Several state approvals also would be required to implement the proposal, as well as SEC approval. Subject to receipt of required regulatory approvals, TRANSLink is expected to begin operations in early 2003.

4.     Restructuring and Regulation (PSCo and SPS)

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

      In early 2002, PSCo filed to increase rates under the ICA to recover the undercollection of costs through the period ended Dec. 31, 2001 (approximately $14.5 million, which went into effect on April 15, 2002), and to increase the ICA base rate for the recovery of 2002 costs, which are projected to be substantially higher than the $12.78 per megawatt hour currently being recovered. PSCo’s actual ICA base costs for 2001 were approximately $19 per megawatt hour. PSCo proposed to increase the ICA base in 2002 to avoid the significant deferral of costs and a large rate increase in 2003, although the Stipulation and Agreement provided for a rate recovery period of April 1, 2003, to March 31, 2004.

      On May 10, 2002, the CPUC approved a Settlement Agreement between PSCo and other parties to increase the ICA base rate to $14.88 per megawatt hour, providing for recovery of the deferred 2001 costs and the projected higher 2002 costs over a 34-month period from June 1, 2002, to March 31, 2005. The review and approval of actual costs incurred and recoverable under the ICA for 2001 and 2002 will be conducted in future rate proceedings by the CPUC for consideration of further increases in the ICA base rate to $19.00 per megawatt hour. PSCo is currently projecting its costs for 2002 to be approximately $38 million less than the ICA base allowed using the 2001 test year, resulting in an equal sharing of such lower costs between retail customers and PSCo. The mechanism for recovering fuel and energy costs for 2003 and later will be addressed in the 2002 rate case.

      Colorado Rate Proceedings — Gas Cost Prudence Review — In May 2002, the staff of the CPUC filed testimony in PSCo’s gas cost prudence review case, recommending $6.1 million in disallowances of gas costs for the July 2000 through June 2001 gas purchase year. PSCo’s rebuttal testimony is scheduled to be filed on June 26, 2002. Hearings are scheduled for July 2002.

      FERC Investigation — On May 8, 2002, the FERC ordered all sellers of wholesale electricity and/or ancillary services to the California Independent System Operator or Power Exchange, including PSCo, to respond to data requests, including requests for admissions with respect to certain trading strategies in which the companies may have engaged. The investigation is in response to memoranda prepared by Enron

17

NOTES TO FINANCIAL STATEMENTS — (Continued)

Corporation that detail certain trading strategies engaged in 2000 and 2001, which may have violated market rules. Xcel Energy must respond by May 22, 2002.

      SPS Texas Transition to Competition Cost Recovery Application — In December 2001, SPS filed an application with the Public Utility Commission of Texas (PUCT) to recover $20.3 million in transition to retail competition costs from the Texas retail customers. These costs are associated with the SPS’ delayed transition to competition. The filing was amended in March 2002 to reduce the recoverable costs by $7.3 million, which were associated with over-earnings recognized in 2001 for the 1999 annual report to the PUCT. The PUCT approved SPS using the 1999 annual report over-earnings to offset the claims for reimbursement of transition to competition costs. This reduced the requested net collection in Texas to $13.0 million. In April 2002, a unanimous settlement agreement was reached. Final approval by the PUCT is expected May 23, 2002. The stipulation provides for the recovery of $5.9 million through an incremental cost recovery rider and the capitalization of $1.9 million for metering equipment. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million in the first quarter of 2002. Recovery of the $5.9 million will begin in July 2002.

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

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

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

      The circumstances set forth in Notes 13 and 14 to the financial statements in NSP-Minnesota’s, NSP-Wisconsin’s, PSCo’s and SPS’ Annual Reports on Form 10-K for the year ended Dec. 31, 2001, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference. Following are unresolved contingencies, which are material to the financial position of Xcel Energy’s Utility Subsidiaries:

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

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

     NSP-Minnesota

      At March 31, 2002, NSP-Minnesota had approximately $376 million of short-term debt outstanding at a weighted average interest rate of 3.153 percent.

     NSP-Wisconsin

      At March 31, 2002, NSP-Wisconsin had approximately $9 million of short-term notes payable to NSP-Minnesota outstanding at a weighted average interest rate of 3.153 percent.

     PSCo

      At March 31, 2002, PSCo had approximately $545 million of short-term debt outstanding at a weighted average interest rate of 3.097 percent.

18

NOTES TO FINANCIAL STATEMENTS — (Continued)

7.     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 financial instruments be recorded on the balance sheet at fair value unless exempted. Changes in a derivative instrument’s fair value must be recognized currently in earnings unless the derivative has been designated in a qualifying hedging relationship. The application of hedge accounting allows a derivative instrument’s gains and losses to offset related results of the hedged item in the income statement, to the extent effective. SFAS No. 133 requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

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

	Three Months Ended
	March 31, 2002
	NSP-Minnesota			PSCo			SPS
	(Millions of Dollars)
Balance at Jan. 1, 2002	$	0.1		$	(4.3	)	$	(4.4	)
After-tax net unrealized (losses) gains 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	)

	Three Months Ended
	March 31, 2001
	NSP-Minnesota			PSCo			SPS
	(Millions of Dollars)
Net unrealized transition gain (loss) at adoption, Jan. 1, 2001	$	0.0		$	1.6		$	(2.6	)
After-tax net unrealized losses related to derivatives accounted for as hedges		(0.0	)		(3.4	)		(1.3	)
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(0.0	)		(1.0	)		0.1
Accumulated other comprehensive loss related to SFAS No. 133 — March 31, 2001	$	(0.0	)	$	(2.8	)	$	(3.8	)

      PSCo recorded pretax gains in Electric Fuel and Purchased Power of $0.1 million and $1.1 million for the three months ended March 31, 2002 and 2001, respectively, due to the effects of SFAS No. 133. NSP-Minnesota and SPS did not realize any impact to earnings related to SFAS No. 133 during the period.

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.

19

NOTES TO FINANCIAL STATEMENTS — (Continued)

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

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

Cash Flow Hedges

      NSP-Minnesota, PSCo and SPS enter into derivative instruments to manage their respective exposure to changes in commodity prices. These derivative instruments take the form of fixed price, floating price or index sales or purchases and options, such as puts, calls and swaps. These derivative instruments are designated as cash flow hedges for accounting purposes and the changes in the fair value of these instruments are recorded as a component of Other Comprehensive Income. At March 31, 2002, NSP-Minnesota, PSCo and SPS had various commodity related contracts through the next 12 months. Earnings on these cash flow hedges are recorded as the hedged purchase or sales transaction is completed. This could include the physical sale of electric energy or the usage of natural gas to generate electric energy. As of March 31, 2002, NSP-Minnesota and PSCo expect to reclassify into earnings through March 2003 net (losses) gains from Other Comprehensive Income of approximately $(0.2) million and $3.6 million, respectively. SPS expects to reclassify an immaterial amount from Other Comprehensive Income into earnings through March 2003.

      As required by SFAS No. 133, PSCo recorded gains of $0.1 million and $0.3 million related to ineffectiveness on commodity cash flow hedges during the three months ended March 31, 2002 and 2001, respectively. During the first quarter of 2001, PSCo recorded gains of $1.4 million related to derivative financial instruments excluded from the assessment of effectiveness and an immaterial amount related to cash flow hedges that were discontinued because the hedged transactions were no longer probable.

      SPS enters into interest rate swap instruments that effectively fix the interest payments on certain floating rate debt obligations. These derivative instruments are designated as cash flow hedges for accounting purposes and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. SPS expects to reclassify into earnings through March 2003 net losses from Other Comprehensive Income of approximately $0.7 million.

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

Derivatives Not Qualifying for Hedge Accounting

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

20

NOTES TO FINANCIAL STATEMENTS — (Continued)

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

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

NSP-Minnesota

		Electric		Gas					Consolidated
		Utility		Utility		All Other			Total
		(Thousands of Dollars)
Three months ended
March 31, 2002
Revenues from:
External customers		$	550,787	$	187,213	$	6,733		$	744,733
Internal customers			163		323		—			486
	Total revenue		550,950		187,536		6,733			745,219
Segment net income		$	28,062	$	4,647	$	324		$	33,033
March 31, 2001
Revenues from:
External customers		$	613,936	$	351,166	$	15,220		$	980,322
Internal customers			179		1,572		—			1,751
	Total revenue		614,115		352,738		15,220			982,073
Segment net income		$	26,162	$	16,133	$	(123	)	$	42,172

NSP-Wisconsin

		Electric		Gas				Consolidated
		Utility		Utility		All Other		Total
Three months ended
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		$	15,209	$	2,721	$	21	$	17,951
March 31, 2001
Revenues from:
External customers		$	113,842	$	69,109	$	125	$	183,076
Internal customers			50		441		—		491
	Total revenue		113,892		69,550		125		183,567
Segment net income		$	8,118	$	4,974	$	—	$	13,092

21

NOTES TO FINANCIAL STATEMENTS — (Continued)

PSCo

		Electric		Gas				Consolidated
		Utility		Utility		All Other		Total
Three months ended
March 31, 2002
Revenues from:
External customers		$	737,857	$	316,851	$	7,765	$	1,062,473
Internal customers			51		14		—		65
	Total revenue		737,908		316,865		7,765		1,062,538
Segment net income		$	44,485	$	20,972	$	1,234	$	66,691
March 31, 2001
Revenues from:
External customers		$	888,081	$	547,239	$	12,284	$	1,447,604
Internal customers			33		561		—		594
	Total revenue		888,114		547,800		12,284		1,448,198
Segment net income		$	70,185	$	25,309	$	11,896	$	107,390

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 $211.7 million and $329.2 million for the three months ended March 31, 2002 and 2001, respectively.

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

NSP-Minnesota

      The components of total comprehensive income are shown below:

		Three Months Ended
		March 31
		2002			2001
		(Thousands
		of Dollars)
Net income		$	33,033		$	42,172
Other comprehensive loss:
	After-tax net unrealized losses on derivatives accounted for as hedges (see Note 7)		(103	)		—
	After-tax net realized gains on derivative transactions reclassified into earnings (see Note 7)		(198	)		—
	Unrealized loss — marketable securities		(8	)		—
Other comprehensive loss			(309	)		—
Comprehensive income		$	32,724		$	42,172

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

22

NOTES TO FINANCIAL STATEMENTS — (Continued)

     NSP-Wisconsin

      For NSP-Wisconsin, comprehensive income equals net income for the quarter ended March 31, 2002 and 2001.

     PSCo

      The components of total comprehensive income are shown below:

		Three Months Ended
		March 31
		2002			2001
		(Thousands of Dollars)
Net income		$	66,691		$	107,390
Other comprehensive income (loss):
	Cumulative effect of accounting change — net unrealized transition gain upon adoption of SFAS No. 133		—			1,649
	After-tax net unrealized gains (losses) on derivatives accounted for as hedges (see Note 7)		8,724			(3,415	)
	After-tax net realized gains on derivative transactions reclassified into earnings (see Note 7)		(838	)		(1,057	)
Other comprehensive income (loss)			7,886			(2,823	)
Comprehensive income		$	74,577		$	104,567

      The accumulated comprehensive income in stockholder’s equity at March 31, 2002 and 2001, relates to valuation adjustments on derivative financial instruments and hedging activities and the mark-to-market component of our marketable securities.

     SPS

      The components of total comprehensive income are shown below:

		Three Months Ended
		March 31
		2002			2001
		(Thousands
		of Dollars)
Net income		$	14,748		$	26,049
Other comprehensive income:
	Cumulative effect of accounting change — net unrealized transition loss upon adoption of SFAS No. 133		—			(2,626	)
	After-tax net unrealized losses on derivatives accounted for as hedges (see Note 7)		(289	)		(1,248	)
	After-tax net realized losses on derivative transactions reclassified into earnings (see Note 7)		203			118
Other comprehensive loss			(86	)		(3,756	)
Comprehensive income		$	14,662		$	22,293

      The accumulated comprehensive loss in stockholder’s equity at March 31, 2002 and 2001, relates to valuation adjustments on derivative financial instruments and hedging activities.

23

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;

•  business conditions in the energy industry;

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

•  unusual weather;

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

•  risks associated with the California 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, 2001. Commodity price and interest rate risks for the Utility Subsidiaries of Xcel Energy are mitigated in most jurisdictions due to cost-based rate regulation. There have been no material changes in the market risk exposures that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2001.

Pending Accounting Changes

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

24

      NSP-Minnesota currently follows industry practice by ratably accruing the costs for decommissioning over the approved cost recovery period and including the accruals in accumulated depreciation. At Dec. 31, 2001, NSP-Minnesota recorded and recovered in rates $623 million of decommissioning obligations and had estimated discounted decommissioning cost obligations of $878 million.

      If NSP-Minnesota adopted the standard on Jan. 1, 2002, the initial value of the liability, including cumulative interest expense through that date, would have been approximately $757 million, with a corresponding increase to net plant assets of approximately $625 million. The resulting cumulative effect adjustment for unrecognized depreciation and other expenses under the new standard is approximately $132 million. Management expects that the entire transition amount would be recoverable in rates and, therefore, would recognize an additional regulatory asset upon adoption of SFAS No. 143 rather than incur a cumulative effect charge against earnings.

      SFAS No. 143 also will affect accrued plant removal costs for other generation, transmission and distribution facilities for all of the Utility Subsidiaries. Xcel Energy expects that these costs, which have yet to be estimated, are expected to be reclassified from accumulated depreciation to regulatory liabilities based on the treatment of these costs in rates. Xcel Energy expects to adopt SFAS 143 as required on Jan. 1, 2003.

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

25

NSP-MINNESOTA’S MANAGEMENT’S DISCUSSION AND ANALYSIS

Results of Operations

      NSP-Minnesota’s net income was approximately $33.0 million for the first three months of 2002, compared with approximately $42.2 million for the first three months of 2001.

     Electric Utility and Commodity Trading Margins

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

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

							Electric
	Electric			Short-term			Commodity			Consolidated
	Utility			Wholesale			Trading			Total
	(Millions of Dollars)
Three months ended 3/31/2002
Electric utility revenue	$	514		$	24		$	—		$	538
Electric trading revenue		—			—			13			13
Electric fuel and purchased power-utility		(166	)		(18	)		—			(184	)
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	%
Three months ended 3/31/2001
Electric utility revenue	$	568		$	46		$	—		$	614
Electric trading revenue		—			—			—			—
Electric fuel and purchased power-utility		(210	)		(33	)		—			(243	)
Electric trading costs		—			—			—			—
Gross margin before operating expenses	$	358		$	13		$	—		$	371
Margin as a percentage of revenue		63.0	%		28.3	%		—			60.4	%

      Electric utility revenues decreased by $54 million, or 9.5 percent, in the first quarter of 2002, compared with the same period in 2001. Electric utility margins decreased by $10 million, or 2.8 percent in 2002 when compared with 2001. The decrease in revenues and margins reflect lower shared trading margins recorded through the JOA and warmer temperatures in 2002. Revenues also were reduced by lower purchased power costs recovered through electric rates. These decreases in revenues and margin were partially offset by sales growth and the timing of recognition of conservation incentive revenues.

      Short-term wholesale margins decreased in the first three months of 2002, compared with the first three months of 2001. The decrease is due to declines in energy prices.

26

     Gas Utility Margins

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

	Three Months Ended
	March 31
	2002			2001
	(Millions of Dollars)
Gas revenue	$	188		$	353
Cost of gas sold and transported		(128	)		(288	)
Gas utility margin	$	60		$	65

      Gas revenue decreased by approximately $165 million, or 46.7 percent, in the first quarter of 2002, primarily due to decreases in the cost of natural gas, which are largely passed on to customers and recovered through various rate adjustment clauses. Gas margin for the first three months of 2002 decreased by $5 million, or 7.7 percent, compared with the first three months of 2001, primarily due to warmer winter temperatures in the first three months of 2002.

     Non-Fuel Operating Expense and Other Items

      Other Operating and Maintenance Expense increased by approximately $6 million, or 2.8 percent, for the first three months of 2002, compared with the first three months of 2001. The increased costs in the first quarter reflect higher outage costs, higher property insurance premiums and higher nuclear operating costs.

      Depreciation and Amortization Expense increased by approximately $2.3 million, or 2.7 percent, for the first three months of 2002, compared with the first three months of 2001, primarily due to capital additions to utility plant.

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

      Other Income (Expense) — net increased by $8.9 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 decreased by approximately $7.5 million, or 30.0 percent, for the first three months of 2002, compared with the first three months of 2001. The change is largely due to lower average debt levels and lower short-term interest rates.

      Taxes (other than income taxes) declined largely due to a legislative change in Minnesota that reduced annual property taxes by approximately $30 million in September 2001 that related proportionately to the first nine months of 2001. Approximately 70 percent of this reduction in property taxes will be returned to NSP-Minnesota customers.

27

NSP-WISCONSIN’S MANAGEMENT’S DISCUSSION AND ANALYSIS

Results of Operations

      NSP-Wisconsin’s net income was $18.0 million for the first three months of 2002, compared with $13.1 million for the first three months of 2001.

     Electric Utility Margins

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

		Three Months Ended
		March 31,
		2002			2001
		(Millions of Dollars)
Total electric utility revenue		$	117		$	114
Electric fuel and purchased power			(55	)		(61	)
	Total electric utility margin	$	62		$	53

      Electric utility revenue increased by approximately $3 million, or 2.6 percent, in the first three months of 2002, compared with the first three months of 2001. Electric utility margin increased by approximately $9 million, or 16.9 percent, in the first three months of 2002, compared with the first three months of 2001. The revenue increase reflects a rate increase and sales growth, partially offset by the impact of warmer weather. The increase in electric margin is primarily due to lower fuel and purchased power costs in 2002 and an increase in base electric rates effective Oct. 18, 2001, for Wisconsin retail customers. Warmer temperatures in 2002, compared with 2001, reduced electric margins.

     Gas Utility Margins

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

	Three Months Ended
	March 31
	2002			2001
	(Millions of Dollars)
Gas revenue	$	40		$	70
Cost of gas purchased and transported		(29	)		(57	)
Gas margin	$	11		$	13

      Gas revenue for the first three months of 2002 decreased by $30 million, or 42.9 percent, compared with the first three months of 2001, due to lower sales and decreases in the cost of gas, which is recovered in Wisconsin through the purchased gas adjustment clause mechanism. Gas margin for the first three months of 2002 decreased by $2 million, or 15.4 percent, compared with the first three months of 2001, primarily due to less favorable temperatures in 2002.

Non-Fuel Operating Expense and Other Items

      Other Operating and Maintenance Expense for the first three months of 2002 decreased by $1.6 million, or 6.2 percent, compared with the first three months of 2001, primarily due to lower conservation expenditures and lower shared costs in 2002.

28

      Depreciation and Amortization Expense increased by approximately $0.5 million, or 5.0 percent, for the first three months of 2002, compared with the first three months of 2001, due largely to increased capital additions to utility plant.

      As discussed in Note 2 to the Financial Statements, during fourth the quarter of 2001, NSP-Wisconsin expensed pretax special charges for planned staff consolidation costs. In the first quarter of 2002, additional pretax special charges of $0.5 million were expensed for the final 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 increased $0.5 million, or 179.6 percent, for the first three months of 2002, compared with the first three months of 2001, primarily due to interest income received on outstanding economic development loans.

      Interest expense increased by approximately $0.3 million, or 5.3 percent, for the first three months of 2002, compared with the first three months of 2001, due largely to a regulatory amortization for an interest refund in 2001 that did not recur in 2002.

29

PSCo’S MANAGEMENT’S DISCUSSION AND ANALYSIS

Results of Operations

      PSCo’s net income was approximately $66.7 million for the first three months of 2002, compared with approximately $107.4 million for the first three months of 2001.

     Electric Utility and Commodity Trading Margins

      Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel clause cost recovery mechanisms for retail customers in Colorado, most fluctuations in energy costs do not materially affect electric margin. Electric margins reflect the impact of sharing energy costs and savings relative to a target cost per delivered kilowatt hour and certain trading margins under the ICA. In addition to the ICA, PSCo has other adjustment clauses that allow certain costs to be passed through to retail customers. The Qualifying Facilities Capacity Cost Adjustment (QFCCA) provides for recovery of purchased capacity costs from certain Qualifying Facilities projects not otherwise reflected in based electric rates. The fuel clause cost recovery does not allow for complete recovery of all variable production expenses and higher costs can adversely affect earnings.

      Some electric commodity trading activity, 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, discussed later. Trading margins reflect the impact of sharing certain trading margins under the ICA. The following table details electric utility, short-term wholesale and electric trading revenue and margin.

							Electric
	Electric			Short-term			Commodity			Consolidated
	Utility			Wholesale			Trading			Total
	(Millions of Dollars)
3 months ended 3/31/2002
Electric utility revenue	$	422		$	16		$	—		$	438
Electric trading revenue		—			—			300			300
Electric fuel and purchased power-utility		(192	)		(17	)		—			(209	)
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	%
3 months ended 3/31/2001
Electric utility revenue	$	351		$	239		$	—		$	590
Electric trading revenue		—			—			298			298
Electric fuel and purchased power-utility		(174	)		(167	)		—			(341	)
Electric trading costs		—			—			(277	)		(277	)
Gross margin before operating expenses	$	177		$	72		$	21		$	270
Margin as a percentage of revenue		50.4	%		30.1	%		7.0	%		30.4	%

      Electric utility margin increased by approximately $53 million, or 29.9 percent, in the first three months of 2002, compared with the first three months of 2001. The higher electric margins reflect lower unrecovered costs, due in part to resetting the base-cost recovery factor through the ICA in January 2002.

30

      Short-term wholesale margins and electric commodity trading margins decreased substantially in the first three months of 2002, compared with the first three months of 2001. The decrease is due to declines in energy prices. During 2001, in some Western markets, publicly available power prices ranged from $80 to more than $350 per megawatt-hour on a monthly average. Forward price information for 2002 for these same areas ranges from $60 to $110 per megawatt-hour on a monthly average.

     Gas Utility Margins

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

	Three Months Ended
	March 31
	2002			2001
	(Millions of Dollars)
Gas revenue	$	317		$	548
Cost of gas purchased and transported		(211	)		(448	)
Gas margin	$	106		$	100

      Gas revenue for the first three months of 2002 decreased by approximately $231 million, or 42.2 percent, compared with the first three months of 2001, largely due to lower gas costs recovered through rates. Gas margin for the first three months of 2002 increased by approximately $6 million, or 6.0 percent, compared with the first three months of 2001, primarily due to higher rates from a 2000 rate case, effective Feb. 1, 2001.

     Non-Fuel Operating Expense and Other Items

      Other Operation and Maintenance Expense increased by approximately $15.0 million, or 14.7 percent, for the first three months of 2002, compared with the first three months of 2001. The change is largely due to generation maintenance overhauls, higher information technology infrastructure costs and higher property insurance premiums.

      Depreciation and Amortization Expense increased by approximately $6.5 million, or 11.1 percent, for the first three months of 2002, compared with the first three months of 2001, primarily due to increased amortization costs of software and increased depreciation resulting from capital additions to utility plant.

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

      Interest expense decreased by approximately $2.5 million, or 8.3 percent, for the first three months of 2002, compared with the first three months of 2001. The decrease was primarily due to lower interest rates.

31

SPS’ MANAGEMENT’S DISCUSSION AND ANALYSIS

Results of Operations

      SPS’ net income was approximately $14.7 million for the first three months of 2002, compared with approximately $26 million for the first three months of 2001.

     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.

							Electric
	Electric			Short-term			Commodity		Consolidated
	Utility			Wholesale			Trading		Total
	(Millions of Dollars)
3 months ended 3/31/2002
Electric utility revenue	$	210		$	2		$	—	$	212
Electric trading revenue		—			—			—		—
Electric fuel and purchased power-utility		(96	)		(2	)		—		(98	)
Electric trading costs		—			—			—		—
Gross margin before operating expenses	$	114		$	—		$	—	$	114
Margin as a percentage of revenue		54.3	%		—			—		53.8	%
3 months ended 3/31/2001
Electric utility revenue	$	328		$	1		$	—	$	329
Electric trading revenue		—			—			—		—
Electric fuel and purchased power-utility		(203	)		(1	)		—		(204	)
Electric trading costs		—			—			—		—
Gross margin before operating expenses	$	125		$	—		$	—	$	125
Margin as a percentage of revenue		38.1	%		—			—		38.0	%

      Electric revenue decreased by approximately $117 million, or 35.6 percent, for the first three months of 2002, compared with the first three months of 2001. Electric margin decreased by approximately $11 million, or 8.8 percent, for the first three months of 2002, compared with the first three months of 2001. Electric revenues decreased for the first three months of 2002, largely due to lower fuel and purchased power costs recovered through electric rates and lower sharing of commodity trading activity initially recorded at PSCo and NSP-Minnesota through the JOA approved by the FERC. The decrease in retail margin was primarily due to the lower revenues shared through the JOA.

     Non-Fuel Operating Expense and Other Costs

      Other Operation and Maintenance Expense increased by approximately $3.5 million, or 9.6 percent, for the first three months of 2002, compared with the first three months of 2001. The change is largely due to higher plant overhaul costs and higher property insurance premiums.

32

      Depreciation and Amortization Expense increased by approximately $1.7 million, or 8.6 percent, for the first three months of 2002, compared with the first three months of 2001, primarily due to increased depreciation from capital additions to utility plant.

      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.

33

PART II.     OTHER INFORMATION

Item 1.     Legal Proceedings

      In the normal course of business, various lawsuits and claims have arisen against the Utility Subsidiaries of Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. See Notes 4 and 5 of the Financial Statements in this Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 of NSP-Minnesota’s, NSP-Wisconsin’s, PSCo’s and SPS’ 2001 Form 10-K for a description of certain legal proceedings presently pending. There are no new significant cases to report against the Utility Subsidiaries of Xcel Energy and there have been no notable changes in the previously reported proceedings, except as set forth below.

NSP-Minnesota

      Light Rail Lawsuit — In February 2001, NSP-Minnesota filed a lawsuit in the federal district court in Minneapolis seeking reimbursement of costs for relocating electric utility lines to allow for construction of a light rail transit (LRT) line in downtown Minneapolis. In May 2001, the Minnesota Department of Transportation and the Metropolitan Council (Defendants) obtained a preliminary injunction requiring NSP-Minnesota to move certain facilities. NSP-Minnesota has complied with the preliminary injunction and utility line relocation has commenced. NSP-Minnesota is capitalizing its costs incurred as construction work in progress. In April 2002, Defendants brought motions for summary judgment before the federal district court. The court has not yet ruled on these motions and no trial date will be established until such ruling is made. The decision as to who must pay the cost of relocation will be made after trial. In collateral matters regarding LRT construction, NSP-Minnesota has commenced a mandamus action in state court seeking an order requiring Defendants to commence condemnation proceedings concerning an underground substation, access to which is blocked by LRT. NSP-Minnesota also has commenced an action in state court alleging that LRT construction violates the Minnesota Environmental Rights Act and a separate action in federal district court alleging that the Federal Transit Administration’s failure to evaluate certain environmental effects of LRT violates the National Environmental Policy Act.

NSP-Wisconsin

      Stray Voltage — On March 1, 2002, NSP-Wisconsin was served with a lawsuit commenced by James and Grace Gumz and Michael and Susan Gumz in Marathon County Circuit Court, Wisconsin, alleging that electricity supplied by NSP-Wisconsin harmed their dairy herd and caused them personal injury. The Gumz’s complaint alleges negligence, strict liability, nuisance, trespass, and statutory violations and seeks compensatory, punitive and treble damages. The complaint does not specify the amount of damages sought by the plaintiffs.

Item 6.     Exhibits and Reports on Form 8-K

(a) Exhibits

      The following Exhibits are filed with this report:

99.01     Statement pursuant to Private Securities Litigation Reform Act.

(b) Reports on Form 8-K

      The following reports on Form 8-K were filed either during the three months ended March 31, 2002, or between March 31, 2002, and the date of this report:

NSP-Minnesota, NSP-Wisconsin, PSCo and SPS

      March 27, 2002, (filed April 3, 2002) Item 4. Changes In Independent Accountants. Re: Xcel Energy Board approved the decision to engage Deloitte & Touche LLP as its new principal independent accountants for Xcel Energy for 2002.

      May 13, 2002, (filed May 13, 2002) Item 5. Other Events. Re: Xcel Energy transactions with Reliant Energy.

34

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, 2002.

NORTHERN STATES POWER CO.

(a Minnesota corporation)

(Registrant)

By:  /s/ DAVID E. RIPKA

David E. Ripka

Vice President and Controller

By:  /s/ EDWARD J. MCINTYRE

Edward J. McIntyre

Vice President and Chief Financial Officer

35

NORTHERN STATES POWER CO. (A WISCONSIN 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, 2002.

NORTHERN STATES POWER CO.

(a Wisconsin corporation)

(Registrant)

By:  /s/ DAVID E. RIPKA

David E. Ripka

Vice President and Controller

By:  /s/ EDWARD J. MCINTYRE

Edward J. McIntyre

Vice President and Chief Financial Officer

36

PUBLIC SERVICE CO. OF COLORADO 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, 2002.

PUBLIC SERVICE CO. OF COLORADO

(Registrant)

By:  /s/ DAVID E. RIPKA

David E. Ripka

Vice President and Controller

By:  /s/ EDWARD J. MCINTYRE

Edward J. McIntyre

Vice President and Chief Financial Officer

37

SOUTHWESTERN PUBLIC SERVICE CO. 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, 2002.

SOUTHWESTERN PUBLIC SERVICE CO.

(Registrant)

By:  /s/ DAVID E. RIPKA

David E. Ripka

Vice President and Controller

By:  /s/ EDWARD J. MCINTYRE

Edward J. McIntyre

Vice President and Chief Financial Officer

38 EX-99.01 3 c69614ex99-01.htm EX-99.01 STATEMENT PURSUANT TO PRIVATE SECURITIES

Exhibit 99.01

Utility Subsidiaries of Xcel Energy Cautionary Factors

The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage such disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements are made in written documents and oral presentations of the Utility Subsidiaries of Xcel Energy. These statements are based on management’s beliefs as well as assumptions and information currently available to management. When used in the Utility Subsidiaries of Xcel Energy’s documents or oral presentations, the words “anticipate,” “estimate,” “expect,” “projected,” objective,” “outlook,” “forecast,” “possible,” “potential” and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the actual results of the Utility Subsidiaries of Xcel Energy to differ materially from those contemplated in any forward-looking statements include, among others, the following:

• Economic conditions, including inflation rates and monetary fluctuations;

• The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the U.S. economy or the risk of increased cost for insurance premiums, security and other items as a consequence of the Sept. 11, 2001, terrorist attacks;

• Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where the Utility Subsidiaries of Xcel Energy have a financial interest;

• Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

• Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the SEC, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;

• Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, Xcel Energy or any of its subsidiaries; or security ratings;

• Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; nuclear or environmental incidents; or electric transmission or gas pipeline constraints;

• Employee workforce factors, including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages;

• Increased competition in the utility industry;

• State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

• Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

• Nuclear regulatory policies and procedures, including operating regulations and spent nuclear fuel storage;

• Social attitudes regarding the utility and power industries;

• Risks associated with the California and other western power markets;

• Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

• Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

• Factors associated with nonregulated investments, including conditions of final legal closing, foreign government actions, foreign economic and currency risks, political instability in foreign countries, partnership actions, competition, operating risks, dependence on certain suppliers and customers, domestic and foreign environmental and energy regulations; and

• Other business or investment considerations that may be disclosed from time to time in the SEC filings of the Utility Subsidiaries of Xcel Energy or in other publicly disseminated written documents.

The Utility Subsidiaries of Xcel Energy undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exhaustive.

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EX-99.01

ex99-01