Northern States Power 10Q 2001 Q2 Quarterly report

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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 June 30, 2001

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

For the transition period from to

Commission File Number	Exact name of registrant as specified in its charter, State or other jurisdiction of incorporation or organization, Address of principal executive offices and Registrant's Telephone Number, including area code	IRS Employer 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, Wisc. 54701 Telephone (715) 839-2621	39-0508315
001-3280	PUBLIC SERVICE COMPANY OF COLORADO (a Colorado Corporation) 1225 17^th Street, Denver, Colo. 80202 Telephone (303) 571-7511	84-0296600
001-3789	SOUTHWESTERN PUBLIC SERVICE COMPANY (a New Mexico Corporation) Tyler at Sixth, Amarillo, Tex. 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 / /

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 July 31, 2001:

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

Table of Contents

PART I—FINANCIAL INFORMATION
Item l.	Financial Statements	3
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	38
Item 6.	Exhibits and Reports on Form 8-K	39

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

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

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

PART 1. FINANCIAL INFORMATION

Item 1. CONSOLIDATED FINANCIAL STATEMENTS

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(Thousands of Dollars)

			Three Months Ended June 30					Six Months Ended June 30
			2001		2000			2001		2000
Operating revenues:
	Electric utility		$	654,359	$	561,616		$	1,268,474	$	1,111,630
	Gas utility			92,932		71,766			445,670		235,269

		Total operating revenues		747,291		633,382			1,714,144		1,346,899
Operating expenses:
	Electric fuel and purchased power			241,812		188,380			484,859		385,838
	Cost of gas sold and transported			66,123		44,984			354,515		155,487
	Other operating and maintenance expenses			191,699		188,666			391,423		379,976
	Depreciation and amortization			83,415		80,815			166,594		161,249
	Taxes (other than income taxes)			49,493		51,094			101,341		104,149

		Total operating expenses		632,542		553,939			1,498,732		1,186,699

Operating income				114,749		79,443			215,412		160,200
Other income (deductions)—net				1,401		(2,068	)		339		107
Interest charges and financing costs:
	Interest charges—net of amounts capitalized			19,224		30,827			44,338		60,806
	Distributions on redeemable preferred securities of subsidiary trust			3,937		3,937			7,875		7,875

		Total interest charges and financing costs		23,161		34,764			52,213		68,681

Income before income taxes				92,989		42,611			163,538		91,626
Income taxes				36,588		15,740			64,965		34,518

Net income			$	56,401	$	26,871		$	98,573	$	57,108

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

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

				Six Months Ended June 30
				2001			2000
Operating activities:
	Net income			$	98,573		$	57,108
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			173,724			169,692
		Nuclear fuel amortization			21,059			20,675
		Deferred income taxes			10,392			(15,675	)
		Amortization of investment tax credits			(4,095	)		(4,133	)
		Allowance for equity funds used during construction			(4,639	)		(535	)
		Conservation incentive adjustments			(32,218	)		9,918
		Change in accounts receivable			52,785			68,392
		Change in inventories			8,122			5,563
		Change in other current assets			55,198			(30,496	)
		Change in accounts payable			(119,422	)		(17,482	)
		Change in other current liabilities			(74,406	)		(4,378	)
		Change in other assets and liabilities			1,581			23,485

			Net cash provided by operating activities		186,654			282,134
Investing activities:
	Capital/construction expenditures				(194,261	)		(180,207	)
	Allowance for equity funds used during construction				4,639			535
	Investments in external decommissioning fund				(28,446	)		(26,443	)
	Other investments—net				(9,908	)		(3,421	)

			Net cash used in investing activities		(227,976	)		(209,536	)
Financing activities:
	Short-term borrowings—net				(51,327	)		122,143
	Proceeds from issuance of long-term debt				0			76,125
	Repayment of long-term debt, including reacquisition premiums				(970	)		(76,932	)
	Capital contributions from parent				175,000			0
	Dividends and cash distributions paid to parent				(74,864	)		(175,577	)

			Net cash provided by (used in) financing activities		47,839			(54,241	)

	Net increase in cash and cash equivalents				6,517			18,357
	Cash and cash equivalents at beginning of period				11,926			11,344

	Cash and cash equivalents at end of period			$	18,443		$	29,701

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

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

			June 30 2001			Dec. 31 2000
ASSETS
Current assets:
	Cash and cash equivalents		$	18,443		$	11,926
	Accounts receivable—net of allowance for bad debts of $5,915 and $4,952, respectively			236,230			281,611
	Accounts receivable from affiliates			42,295			49,699
	Accrued unbilled revenues			121,059			194,547
	Materials and supplies inventories at average cost			106,844			103,863
	Fuel and gas inventories at average cost.			40,672			51,775
	Prepayments and other			60,701			44,843

		Total current assets		626,244			738,264

Property, plant and equipment, at cost:
	Electric utility			6,407,444			6,388,697
	Gas utility			670,689			666,078
	Other and construction work in progress			667,498			531,678

		Total property, plant and equipment		7,745,631			7,586,453
	Less: accumulated depreciation			(4,165,848	)		(4,017,813	)
	Nuclear fuel—net of accumulated amortization of $988,987 and $967,928, respectively			80,160			86,499

		Net property, plant and equipment		3,659,943			3,655,139

Other assets:
	Nuclear decommissioning fund investments			571,534			563,812
	Other investments			26,974			24,892
	Regulatory assets			204,217			226,547
	Other			209,100			151,334

		Total other assets		1,011,825			966,585

		Total Assets	$	5,298,012		$	5,359,988

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	303,584		$	303,773
	Short-term debt			307,861			359,189
	Accounts payable			186,247			303,053
	Accounts payable to affiliates			28,349			30,965
	Taxes accrued			92,338			130,870
	Other			129,007			162,683

		Total current liabilities		1,047,386			1,290,533

Deferred credits and other liabilities:
	Deferred income taxes			686,948			678,849
	Deferred investment tax credits			86,993			91,088
	Regulatory liabilities			473,520			496,313
	Benefit obligations and other			150,427			146,541

		Total deferred credits and other liabilities		1,397,888			1,412,791

Long-term debt				1,045,581			1,048,995
Mandatorily redeemable preferred securities of subsidiary trust				200,000			200,000
Common stock—authorized 5,000,000 shares of $0.01 par value, outstanding 1,000,000 shares				10			10
Premium on common stock				661,196			479,387
Retained earnings				967,453			952,889
Leveraged shares held by ESOP at cost				(21,502	)		(24,617	)

		Total common stockholder's equity		1,607,157			1,407,669
Commitments and Contingent Liabilities (see Note 5)

		Total Liabilities and Equity	$	5,298,012		$	5,359,988

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

NSP-WISCONSIN

STATEMENTS OF INCOME (UNAUDITED)

(Thousands of Dollars)

			Three Months Ended June 30				Six Months Ended June 30
			2001		2000		2001		2000
Operating revenues:
	Electric utility		$	103,943	$	98,674	$	217,835	$	204,567
	Gas utility			17,976		14,827		87,526		53,388

		Total operating revenues		121,919		113,501		305,361		257,955
Operating expenses:
	Electric fuel and purchased power			58,993		53,330		119,516		106,105
	Cost of gas sold and transported			12,912		10,830		69,944		37,688
	Other operating and maintenance expenses			25,719		25,358		50,551		49,866
	Depreciation and amortization			10,278		9,815		20,521		20,336
	Taxes (other than income taxes)			3,972		3,918		8,034		7,889

		Total operating expenses		111,874		103,251		268,566		221,884

Operating income				10,045		10,250		36,795		36,071
Other income—net				324		598		433		749
Interest charges and financing costs				5,302		4,638		10,841		9,346

Income before income taxes				5,067		6,210		26,387		27,474
Income taxes				1,653		2,166		9,881		10,679

Net income			$	3,414	$	4,044	$	16,506	$	16,795

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

NSP-WISCONSIN

STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

				Six Months Ended June 30
				2001			2000
Operating activities:
	Net income			$	16,506		$	16,795
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			21,027			20,813
		Deferred income taxes			1,546			620
		Amortization of investment tax credits			(410	)		(413	)
		Allowance for equity funds used during construction			(744	)		(153	)
		Undistributed equity earnings of unconsolidated affiliates			(131	)		(175	)
		Change in accounts receivable			11,633			2,909
		Change in inventories			1,178			3,547
		Change in other current assets			14,293			8,805
		Change in accounts payable			(29,464	)		(4,945	)
		Change in other current liabilities			2,009			3,257
		Change in other assets and liabilities			(2,752	)		(586	)

			Net cash provided by operating activities		34,691			50,474
Investing activities:
	Capital/construction expenditures				(30,149	)		(50,992	)
	Allowance for equity funds used during construction				744			153
	Other investments—net				21			462

			Net cash used in investing activities		(29,384	)		(50,377	)
Financing activities:
	Short-term borrowings—net				5,900			(16,500	)
	Common stock issued to parent				0			29,977
	Dividends paid to parent				(11,207	)		(13,498	)

			Net cash used in financing activities		(5,307	)		(21	)

	Net increase in cash and cash equivalents				0			76
	Cash and cash equivalents at beginning of period				31			51

	Cash and cash equivalents at end of period			$	31		$	127

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

NSP-WISCONSIN

BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

			June 30 2001			Dec. 31 2000
ASSETS
Current assets:
	Cash and cash equivalents		$	31		$	31
	Accounts receivable—net of allowance for bad debts of $1,131 and $798, respectively			41,814			53,447
	Accrued unbilled revenues			13,880			29,113
	Materials and supplies inventories at average cost			6,640			6,544
	Fuel and gas inventories at average cost.			6,747			8,021
	Prepaid gross receipts tax			12,614			11,515
	Prepayments and other			4,292			4,451

		Total current assets		86,018			113,122

Property, plant and equipment, at cost:
	Electric utility			1,074,280			1,066,446
	Gas utility			123,927			123,979
	Other and construction work in progress			145,979			127,408

		Total property, plant and equipment		1,344,186			1,317,833
	Less: accumulated depreciation			(533,438	)		(515,798	)

		Net property, plant and equipment		810,748			802,035

Other assets:
	Other investments			9,977			9,867
	Regulatory assets			37,676			38,536
	Other			27,038			22,515

		Total other assets		74,691			70,918

		Total Assets	$	971,457		$	986,075

LIABILITIES AND EQUITY
Current Liabilities:
	Current portion of long term debt		$	34		$	34
	Short-term debt—notes payable to affiliate			21,800			15,900
	Accounts payable			15,043			37,981
	Accounts payable to affiliates			17,820			25,202
	Interest accrued			5,646			5,570
	Dividend payable to parent company Xcel Energy			10,751			0
	Accrued payroll			5,695			8,395
	Purchased gas cost recovery liability			4,708			390
	Other			5,314			5,596

		Total current liabilities		86,811			99,068

Deferred credits and other liabilities:
	Deferred income taxes			118,275			115,682
	Deferred investment tax credits			16,040			16,451
	Regulatory liabilities			18,631			18,818
	Benefit obligations and other			33,840			32,787

		Total other liabilities		186,786			183,738

Long-term debt				313,044			313,000
Common stock—authorized 1,000,000 shares of $100 par value, outstanding 933,000 shares				93,300			93,300
Premium on common stock				33,418			33,418
Retained earnings				258,098			263,551

		Total common stockholder's equity		384,816			390,269
Commitments and Contingent Liabilities (see Note 5)

		Total Liabilities and Equity	$	971,457		$	986,075

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

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(Thousands of Dollars)

			Three Months Ended June 30					Six Months Ended June 30
			2001			2000		2001		2000
Operating revenues:
	Electric utility		$	610,135		$	430,777	$	1,199,817	$	834,063
	Electric trading			421,848			102,069		720,280		146,885
	Gas utility			284,734			138,861		832,534		409,582
	Steam utility			2,965			1,988		10,465		5,722

		Total operating revenues		1,319,682			673,695		2,763,096		1,396,252
Operating expenses:
	Electric fuel and purchased power			345,421			204,824		684,236		395,514
	Electric trading costs			413,014			92,158		690,156		132,833
	Cost of gas sold and transported			217,088			84,642		665,384		260,991
	Other operating and maintenance expenses			110,152			93,318		210,189		190,984
	Depreciation and amortization			58,185			51,886		116,281		102,250
	Taxes (other than income taxes)			22,029			20,462		43,878		41,808
	Special charges (see Note 2)			23,018			0		23,018		0

		Total operating expenses		1,188,907			547,290		2,433,142		1,124,380

Operating income				130,775			126,405		329,954		271,872
Other income (deductions)—net				(3,755	)		4,307		1,088		3,869
Interest charges and financing costs:
	Interest charges—net of amount capitalized			29,006			36,335		59,171		73,008
	Distributions on redeemable preferred securities of subsidiary trust			3,800			3,800		7,600		7,600

		Total interest charges and financing costs		32,806			40,135		66,771		80,608

Income before income taxes				94,214			90,577		264,271		195,133
Income taxes				27,912			29,656		90,579		65,453

Net income			$	66,302		$	60,921	$	173,692	$	129,680

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

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

				Six Months Ended June 30
				2001			2000
Operating activities:
	Net income			$	173,692		$	129,680
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			120,468			105,373
		Deferred income taxes			(4,211	)		7,238
		Amortization of investment tax credits			(2,059	)		(2,247	)
		Allowance for equity funds used during construction			(368	)		0
		Special charges			23,018			0
		Change in accounts receivable			54,000			48,337
		Change in inventories			20,658			33,785
		Change in other current assets			219,185			84,431
		Change in accounts payable			(258,954	)		(103,139	)
		Change in other current liabilities			59,247			(19,522	)
		Change in other assets and liabilities			14,667			(12,759	)

			Net cash provided by operating activities		419,343			271,177
Investing activities:
	Capital/construction expenditures				(172,610	)		(155,516	)
	Proceeds from disposition of property, plant and equipment				4,197			3,446
	Allowance for equity funds used during construction				368			0
	Other investments—net				(2,149	)		(700	)

			Net cash used in investing activities		(170,194	)		(152,770	)
Financing activities:
	Short-term borrowings—net				4,575			(60,892	)
	Proceeds from issuance of long-term debt				100,000			99,750
	Repayment of long-term debt, including reacquisition premiums				(240,575	)		(101,636	)
	Dividends paid to parent				(113,136	)		(92,265	)

			Net cash used in financing activities		(249,136	)		(155,043	)

Net increase (decrease) in cash and cash equivalents					13			(36,636	)
Cash and cash equivalents at beginning of period					15,696			51,731

Cash and cash equivalents at end of period				$	15,709		$	15,095

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

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

			June 30 2001			Dec. 31 2000
ASSETS
Current assets:
	Cash and cash equivalents		$	15,709		$	15,696
	Accounts receivable—net of allowance for bad debts of $11,162 and $11,352, respectively			174,957			228,957
	Accrued unbilled revenues			269,924			369,018
	Recoverable purchased gas and electric energy costs			44,560			159,013
	Derivative instruments valuation—at market			103,060			0
	Materials and supplies inventories at average cost			39,691			41,106
	Fuel inventory at average cost			17,649			21,399
	Gas inventory—replacement cost in excess of LIFO: $59,112 and $106,790 respectively			29,319			44,812
	Prepayments and other			19,188			15,974

		Total current assets		714,057			895,975

Property, plant and equipment, at cost:
	Electric utility			5,037,849			4,896,863
	Gas utility			1,373,806			1,345,380
	Other and construction work in progress			848,964			876,332

		Total property, plant and equipment		7,260,619			7,118,575
	Less: accumulated depreciation			(2,657,866	)		(2,576,126	)

		Net property, plant and equipment		4,602,753			4,542,449

Other assets:
	Other investments			13,306			11,158
	Regulatory assets			214,828			251,154
	Other			90,374			73,577

		Total other assets		318,508			335,889

		Total Assets	$	5,635,318		$	5,774,313

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	2,920		$	142,043
	Short-term debt			159,775			155,200
	Derivative instruments valuation—at market			101,269			0
	Accounts payable			300,120			575,948
	Accounts payable to affiliates			63,447			46,573
	Taxes accrued			69,479			54,718
	Dividends payable			53,786			57,615
	Recovered electric energy costs			23,585			27,060
	Other			194,270			146,309

		Total current liabilities		968,651			1,205,466

Deferred credits and other liabilities:
	Deferred income taxes			546,278			543,715
	Deferred investment tax credits			81,745			83,804
	Regulatory liabilities			49,708			45,027
	Other deferred credits			39,555			24,632
	Customers' advances for construction			80,503			70,714
	Benefit obligations and other			77,782			73,028

		Total deferred credits and other liabilities		875,571			840,920

Long-term debt				1,609,624			1,610,741
Mandatorily redeemable preferred securities of subsidiary trust				194,000			194,000
Common stock—authorized 100 shares of $0.01 par value, outstanding 100 shares				0			0
Premium on common stock				1,574,835			1,574,835
Retained earnings				412,735			348,351
Accumulated other comprehensive income				(98	)		0

		Total common stockholder's equity		1,987,472			1,923,186
Commitments and Contingent Liabilities (see Note 5)

		Total Liabilities and Equity	$	5,635,318		$	5,774,313

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

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF INCOME (UNAUDITED)

(Thousands of Dollars)

			Three Months Ended June 30					Six Months Ended June 30
			2001		2000			2001		2000
Electric utility operating revenues			$	371,681	$	256,643		$	700,954	$	472,875
Operating expenses:
	Electric fuel and purchased power			253,940		126,473			452,318		234,327
	Other operating and maintenance expenses			44,087		40,989			85,670		76,850
	Depreciation and amortization			20,540		19,365			40,809		38,719
	Taxes (other than income taxes)			10,167		11,774			25,076		23,856

		Total operating expenses		328,734		198,601			603,873		373,752

Operating income				42,947		58,042			97,081		99,123
Other income—net				4,467		2,826			6,290		6,236
Interest charges and financing costs:
	Interest charges—net of amounts capitalized			12,808		13,744			24,888		27,086
	Distributions on redeemable preferred securities of subsidiary trust			1,962		1,962			3,925		3,925

		Total interest charges and financing costs		14,770		15,706			28,813		31,011

Income before income taxes and extraordinary item				32,644		45,162			74,558		74,348
Income taxes				12,342		16,516			28,207		27,446

Income before extraordinary item				20,302		28,646			46,351		46,902
Extraordinary item, net of tax (See Note 4)				0		(13,658	)		0		(13,658	)

Net income			$	20,302	$	14,988		$	46,351	$	33,244

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

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

				Six Months Ended June 30
				2001			2000
Operating activities:
	Net income			$	46,351		$	33,244
	Adjustments to reconcile net income to net cash provided by operating activities:
		Extraordinary item			0			13,658
		Depreciation and amortization			42,971			40,483
		Deferred income taxes			100			13,535
		Amortization of investment tax credits			(125	)		(125	)
		Change in accounts receivable			1,325			21,645
		Change in inventories			7,075			2,010
		Change in other current assets			(13,456	)		(83,897	)
		Change in accounts payable			(46,275	)		21,994
		Change in other current liabilities			11,285			6,585
		Change in other assets and liabilities			(13,920	)		(18,970	)

			Net cash provided by operating activities		35,331			50,162
Investing activities:
	Capital/construction expenditures				(66,636	)		(47,647	)
	Proceeds (costs) from disposition of property, plant and equipment				925			(1,927	)
	Other investments—net				119,539			(66	)

			Net cash provided by (used in) investing activities		53,828			(49,640	)
Financing activities:
	Short-term borrowings—net				(30,390	)		133,604
	Repayment of long-term debt, including reacquisition premiums				168			(85,350	)
	Dividends paid to parent				(43,938	)		(40,637	)

			Net cash (used in) provided by financing activities		(74,160	)		7,617

	Net increase in cash and cash equivalents				14,999			8,139
	Cash and cash equivalents at beginning of period				10,826			1,532

	Cash and cash equivalents at end of period			$	25,825		$	9,671

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

SOUTHWESTERN PUBLIC SERVICE CO.

BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

			June 30 2001			Dec. 31 2000
ASSETS
Current assets:
	Cash and cash equivalents		$	25,825		$	10,826
	Accounts receivable—net of allowance for bad debts of $1,454 and $845, respectively			74,170			73,986
	Accounts receivable from affiliates			3,384			4,893
	Accrued unbilled revenues			99,987			87,484
	Recoverable electric energy costs			86,461			104,249
	Materials and supplies inventories at average cost			5,992			13,500
	Fuel and gas inventories at average cost			1,494			1,061
	Prepayments and other			3,543			38

		Total current assets		300,856			296,037

Property, plant and equipment, at cost:
	Electric utility			2,909,459			2,884,702
	Other and construction work in progress			153,567			115,210

		Total property, plant and equipment		3,063,026			2,999,912
	Less: accumulated depreciation			(1,238,480	)		(1,199,158	)

		Net property, plant and equipment		1,824,546			1,800,754

Other assets:
	Notes receivable from affiliate			0			119,036
	Other investments			11,792			12,295
	Regulatory assets			71,325			74,359
	Prepaid pension asset			72,072			61,359
	Other			36,165			28,796

		Total other assets		191,354			295,845

		Total Assets	$	2,316,756		$	2,392,636

LIABILITIES AND EQUITY
Current liabilities:
	Short-term debt		$	644,189		$	674,579
	Accounts payable			58,065			97,285
	Accounts payable to affiliates			6,052			13,107
	Taxes accrued			7,004			19,141
	Interest accrued			4,482			7,139
	Dividends payable			20,626			22,354
	Current portion of accumulated deferred income taxes			32,182			36,307
	Derivative instruments valuation—at market			1,077			0
	Other			67,966			57,122

		Total current liabilities		841,643			927,034

Deferred credits and other liabilities:
	Deferred income taxes			361,786			362,206
	Deferred investment tax credits			4,593			4,718
	Regulatory liabilities			1,205			1,275
	Derivative instruments valuation—at market			6,399			0
	Benefit obligations and other			23,484			19,268

		Total deferred credits and other liabilities		397,467			387,467

Long-term debt				226,682			226,506
Mandatorily redeemable preferred securities of subsidiary trust				100,000			100,000
Common stock—authorized 200 shares of $1.00 par value, outstanding 100 shares				0			0
Premium on common stock				353,099			353,099
Retained earnings				402,670			398,530
Accumulated other comprehensive income				(4,805	)		0

		Total common stockholder's equity		750,964			751,629
Commitments and Contingent Liabilities (see Note 5)

		Total Liabilities and Equity	$	2,316,756		$	2,392,636

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

NOTES TO CONSOLIDATED 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 June 30, 2001, and Dec. 31, 2000, the results of their operations for the three months and six months ended June 30, 2001 and 2000, and their cash flows for the six months ended June 30, 2001 and 2000. Due to the seasonality of electric and gas sales of Xcel Energy's Utility Subsidiaries, quarterly and year-to-date results are not necessarily an appropriate base from which to project annual results.

The accounting policies of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are set forth in Note 1 to the financial statements in their respective Annual Reports on Form 10-K for the year ended Dec. 31, 2000. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K's.

1. Merger to Create Xcel Energy (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

On Aug. 18, 2000, New Century Energies Inc. (NCE) and Northern States Power Co. (NSP) merged and formed Xcel Energy Inc. Xcel Energy, a Minnesota corporation, is a registered holding company under the Public Utility Holding Company Act. Each share of NCE common stock was exchanged for 1.55 shares of Xcel Energy common stock. NSP shares became Xcel Energy shares on a one-for-one basis. The merger was structured as a tax-free, stock-for-stock exchange for shareholders of both companies (except for fractional shares), and accounted for as a pooling-of-interests. Amounts reported for periods prior to the merger have been restated for comparability with post-merger treatment.

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

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

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

During 2000, an allocation of approximately $188 million of merger costs was made to Xcel Energy's Utility Subsidiaries and is reported as special charges. This allocation was made to the various operating utility companies using a basis consistent with prior regulatory filings, in proportion to expected merger savings by company and consistent with service company cost allocation methodologies utilized under Public Utility Holding Company Act requirements. The transition costs included costs for severance and related expenses associated with staff reductions of 721 employees, approximately 680 of whom were released through July 31, 2001.

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

		Dec. 31, 2000 Liability		Accrual Adjustments Expensed	Payments Against Liability			June 30, 2001 Liability
		(Millions of Dollars)
Employee separation & other related costs		$	48	—	$	(18	)	$	30
Regulatory transition costs			5	—		—			5
Other transition and integration costs			2	—		(2	)		—

	Total accrued merger costs—Xcel Energy	$	55	—	$	(20	)	$	35

NSP-Minnesota portion		$	19	—	$	(10	)	$	9
NSP-Wisconsin portion		$	3	—	$	(1	)	$	2
PSCo portion		$	2	—	$	(1	)	$	1
SPS portion		$	1	—		—		$	1

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

In the 1996 rate case, the Colorado Public Utility Commission (CPUC) allowed recovery of postemployment benefit costs on an accrual basis, but denied PSCo's request to amortize the transition costs regulatory asset. PSCo appealed this decision to the Denver District Court. In 1998, the CPUC deferred the final determination of the regulatory treatment of the electric jurisdictional costs pending the outcome of PSCo's appeal on the natural gas rate case. On Dec. 16, 1999, the Denver District Court affirmed the decision by the CPUC.

On Jan. 31, 2000, PSCo filed a Notice of Appeal with the Colorado Supreme Court and in February 2001 presented oral arguments. On July 2, 2001, the Colorado Supreme Court affirmed the District Court decision. Accordingly, PSCo has written off $23 million of regulatory assets related to deferred postemployment benefit costs as of June 30, 2001, since any means of regulatory recovery has been denied.

3. Business Developments (NSP-Minnesota and PSCo)

NSP-Minnesota

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

PSCo

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

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

NSP-Minnesota

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

NSP-Wisconsin

NSP-Wisconsin Electric Power Supply Rate Request—In May 2001, NSP-Wisconsin filed an application with the Public Service Commission of Wisconsin (PSCW) requesting an increase in Wisconsin retail electric rates due to significant increases in power supply costs. This increase is necessary to recover fuel and purchased power costs from wholesale suppliers at market based prices. On June 28, 2001, the PSCW approved an interim fuel cost surcharge, which will increase NSP-Wisconsin's electric revenue by approximately $5.6 million for the last six months of 2001. A hearing will be held on Aug. 16, 2001 to establish a final fuel cost surcharge. An order authorizing the final surcharge is expected in September 2001.

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

Wisconsin Restructuring—The Wisconsin state budget, which passed the legislature and which is expected to be signed by the Governor in the near future, includes a provision which allows for the transfer of utility property for the purpose of creating a generation company organized as a Limited Liability Company (LLC) for the construction of new generation and allows for the establishment of "leased generation contracts" between a regulated utility and the newly organized LLC. Existing generation facilities cannot be transferred. Long-term contracts will be required and a higher authorized rate of return will be possible under this new regulated entity. The PSCW must approve all aspects of the leased generation contract.

SPS

SPS Restructuring—In the second quarter of 2000, SPS discontinued regulatory accounting under SFAS 71 for the generation portion of its business due to the issuance of a written order by the Public Utilities Commission of Texas (PUCT) in May 2000, addressing the implementation of electric utility restructuring. SPS' transmission and distribution business continued to meet the requirements of

SFAS 71, as that business was expected to remain regulated. During the second quarter of 2000, SPS wrote off its generation-related regulatory assets and other deferred costs totaling approximately $19.3 million. This resulted in an after-tax extraordinary charge of approximately $13.7 million. During the third quarter of 2000, SPS recorded an extraordinary charge of $8.2 million before tax, or $5.3 million after tax, related to the tender offer and defeasance of first mortgage bonds. The first mortgage bonds were defeased to facilitate the legal separation of generation, transmission and distribution assets, which was expected to eventually occur in 2001 under restructuring requirements.

In March 2001, the state of New Mexico enacted legislation that delayed customer choice until 2007 and amended the Electric Utility Restructuring Act of 1999. SPS has requested recovery of its costs incurred to prepare for customer choice in New Mexico. A decision on this and other matters is pending before the New Mexico Public Regulation Commission (NMPRC). SPS expects to receive regulatory recovery of these costs through a rate rider in the next New Mexico rate case filed.

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

As a result of these recent legislative developments, SPS reapplied the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" for its generation business during the second quarter of 2001. More than 95 percent of SPS' retail electric revenues are from operations in Texas and New Mexico. Because of the delays to electric restructuring passed by Texas and New Mexico, SPS' previous plans to implement restructuring, including the divestiture of generation assets, have been abandoned. Accordingly, SPS will now continue to be subject to rate regulation under traditional cost of service regulation, consistent with its past accounting and ratemaking practices. At this time, management is uncertain as to whether restructuring will be completed in 2007 or later and as to what the transition plan to competition will be at that time. SPS has not restored regulatory assets or capitalized defeasance costs previously written off in 2000. Due to the regulatory uncertainty regarding the recovery of these costs in future rates, SPS has delayed the restoration of regulatory assets until it is determined that specific regulatory recovery is achieved. Consequently, SPS has not recognized any earnings impact for financial reporting purposes as a result of its reapplication of SFAS 71 through June 30, 2001. However, future regulatory developments may create earnings increases (should additional cost recovery be provided) or decreases (should deferred costs not be fully recovered).

As of June 30, 2001, SPS had incurred approximately $45 million of restructuring costs, including $8 million of debt defeasance costs allocated to the generation business, which was expensed as an extraordinary item in the third quarter of 2000 and $37 million of restructuring costs, which have been deferred based on anticipated future recovery in jurisdictional rates.

SPS Texas Retail Fuel Factor and Fuel Surcharge Application—SPS has filed an application with the PUCT to increase its fixed fuel factor and to surcharge past fuel cost under-recoveries. Intervenors in the proceeding are protesting SPS' application and are claiming SPS should be crediting margins from

wholesale firm sales to Texas retail eligible fuel expenses. Hearings were held in May 2001 and a final decision is pending before the PUCT. SPS and the PUCT Staff oppose the revenue treatment suggested by the intervenors. The final outcome or impact of the wholesale firm sales on Xcel Energy's earnings will not be known until later in 2001.

5. Commitments and Contingent Liabilities (NSP-Wisconsin)

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

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

The circumstances set forth in Notes 12 and 13 to the financial statements in NSP-Minnesota's, NSP-Wisconsin's, PSCo's and SPS' Annual Reports on Form 10-K for the year ended Dec. 31, 2000, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident, except as for the following updated developments.

NSP-Wisconsin

French Island—NSP-Wisconsin's French Island plant generates electricity by burning a mixture of wood waste and refuse derived fuel. The fuel is derived from municipal solid waste furnished under a contract with LaCrosse County, Wisconsin. In 1997, the EPA found that the French Island plant was a "small municipal waste combustor" and therefore not subject to EPA regulations applicable to large combustors. In October 2000, the EPA reversed its decision and found that the plant was subject to the large combustor regulations. Those regulations became effective on Dec. 19, 2000. NSP-Wisconsin did not have adequate time to install the emission controls necessary to come into compliance with the large combustor regulations by the compliance date. As a result, on March 29, 2001, the EPA issued a finding of violation to the company. On April 2, 2001, a conservation group sent NSP-Wisconsin a notice of intent to sue under the citizen suit provisions of the Clean Air Act. On July 27, 2001, the state of Wisconsin filed a lawsuit against NSP-Wisconsin in the Wisconsin Circuit Court for La Crosse County, contending that NSP-Wisconsin exceeded dioxin emission limits on numerous occasions between July 1995 and December 2000 at French Island. NSP-Wisconsin faces fines between $10 and $25,000 for each violation. On July 27, 2001, NSP-Wisconsin filed for a Certificate of Authority to install control equipment necessary to bring the French Island plant into compliance with the large combustor regulations. NSP-Wisconsin plans to begin construction of the new air quality equipment late in 2001 upon issuance of a Certificate of Authority from the PSCW.

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

NSP-Minnesota

At June 30, 2001, NSP-Minnesota had approximately $308 million of short-term debt outstanding at a weighted average interest rate of 4.042 percent.

In April 2001, NSP-Minnesota filed a $600 million long-term debt shelf registration with the SEC. NSP-Minnesota intends to issue debt under this shelf registration during the third quarter of 2001.

NSP-Wisconsin

At June 30, 2001, NSP-Wisconsin had approximately $22 million of short-term notes payable to NSP-Minnesota outstanding at a weighted average interest rate of 4.042 percent.

PSCo

At June 30, 2001, PSCo had approximately $160 million of short-term debt outstanding at a weighted average interest rate of 4.237 percent.

SPS

At June 30, 2001, SPS had approximately $644 million of short-term debt outstanding at a weighted average interest rate of 4.026 percent.

In June 2001, SPS filed a $500 million long-term debt shelf registration with the SEC. SPS plans to issue debt under this shelf registration during the third quarter of 2001. The proceeds from the shelf offering will be used for short-term debt repayment.

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

Xcel Energy's utility subsidiaries each have two reportable segments Electric Utility and Gas Utility, with the exception of SPS, which has only a Electric Utility reportable segment. 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 $371.7 million and $256.6 million for the three months ended June 30, 2001 and 2000, respectively. Revenues from external customers were $701 million and $472.9 million for the six months ended June 30, 2001 and 2000, respectively. All figures are in thousands of dollars.

NSP-Minnesota

Three months ended: June 30, 2001		Electric Utility		Gas Utility			All Other			Consolidated Total
Revenues from:			��
External customers		$	654,192	$	94,360		$	—		$	748,552
Internal customers			167		(1,428	)		—			(1,261	)

	Total revenue		654,359		92,932			—			747,291
Segment net income		$	54,628	$	1,901		$	(128	)	$	56,401
June 30, 2000
Revenues from:
External customers		$	561,462	$	71,291		$	—		$	632,753
Internal customers			154		475			—			629

	Total revenue		561,616		71,766			—			633,382
Segment net income		$	27,405	$	(434	)	$	(100	)	$	26,871

Six months ended: June 30, 2001		Electric Utility		Gas Utility		All Other			Consolidated Total
Revenues from:
External customers		$	1,268,128	$	445,526	$	—		$	1,713,654
Internal customers			346		144		—			490

	Total revenue		1,268,474		445,670		—			1,714,144
Segment net income		$	80,790	$	18,034	$	(251	)	$	98,573
June 30, 2000
Revenues from:
External customers		$	1,111,314	$	234,267	$	—		$	1,345,581
Internal customers			316		1,002		—			1,318

	Total revenue		1,111,630		235,269		—			1,346,899
Segment net income		$	45,285	$	12,027	$	(204	)	$	57,108

NSP-Wisconsin

Three months ended: June 30, 2001		Electric Utility		Gas Utility			All Other		Consolidated Total
Revenues from:
External customers		$	103,900	$	17,525		$	—	$	121,425
Internal customers			43		451			—		494

	Total revenue		103,943		17,976			—		121,919
Segment net income		$	3,411	$	3		$	—	$	3,414
June 30, 2000
Revenues from:
External customers		$	98,638	$	14,429		$	—	$	113,067
Internal customers			36		398			—		434

	Total revenue		98,674		14,827			—		113,501
Segment net income		$	4,528	$	(484	)	$	—	$	4,044

Six months ended: June 30, 2001		Electric Utility		Gas Utility		All Other		Consolidated Total
Revenues from:
External customers		$	217,742	$	86,634	$	—	$	304,376
Internal customers			93		892		—		985

	Total revenue		217,835		87,526		—		305,361
Segment net income		$	11,529	$	4,977	$	—	$	16,506
June 30, 2000
Revenues from:
External customers		$	204,491	$	52,306	$	—	$	256,797
Internal customers			76		1,082		—		1,158

	Total revenue		204,567		53,388		—		257,955
Segment net income		$	12,709	$	4,086	$	—	$	16,795

PSCo

Three months ended: June 30, 2001		Electric Utility		Gas Utility		All Other		Consolidated Total
Revenues from:
External customers		$	1,031,950	$	284,172	$	2,965	$	1,319,087
Internal customers			33		562		—		595

	Total revenue		1,031,983		284,734		2,965		1,319,682
Segment net income		$	57,169	$	2,016	$	7,117	$	66,302
June 30, 2000
Revenues from:
External customers		$	532,846	$	138,861	$	1,988	$	673,695
Internal customers			—		—		—		—

	Total revenue		532,846		138,861		1,988		673,695
Segment net income		$	52,316	$	783	$	7,822	$	60,921

Six months ended: June 30, 2001		Electric Utility		Gas Utility		All Other		Consolidated Total
Revenues from:
External customers		$	1,920,031	$	831,411	$	10,465	$	2,761,907
Internal customers			66		1,123		—		1,189

	Total revenue		1,920,097		832,534		10,465		2,763,096
Segment net income		$	127,354	$	27,325	$	19,013	$	173,692
June 30, 2000
Revenues from:
External customers		$	980,948	$	408,582	$	5,722	$	1,396,252
Internal customers			—		—		—		—

	Total revenue		980,948		408,582		5,722		1,396,252
Segment net income		$	92,786	$	24,858	$	12,036	$	129,680

8. Adoption of SFAS 133 (PSCo and SPS)

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

A fair value hedge requires that the effective portion of the change in the fair value of a derivative instrument be offset against the change in the fair value of the underlying asset, liability, or firm commitment being hedged through earnings. A cash flow hedge requires that the effective portion of the change in the fair value of a derivative instrument be recognized in other comprehensive income,

and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The ineffective portion of any derivative instrument's change in fair value is recognized in earnings. Additionally, both the fair value changes excluded from the effectiveness assessment and the time value component of options used as cash flow hedges are recognized in earnings.

Xcel Energy's Utility Subsidiaries have applied SFAS 133 to energy and energy related commodities financial instruments, long-term power sales contracts and long-term gas purchase contracts used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investment in fuel inventories. SFAS 133 also applies to various interest rate swaps used to mitigate the risks associated with movements in interest rates.

Xcel Energy conducts energy acquisition, wholesale sales and trading activities through its utility operations. The primary objective of Xcel Energy's energy acquisition and trading operations is to maximize asset value while simultaneously minimizing pricing and credit risks. These activities are subject to SFAS 133 as they typically meet the definition of derivative instruments. For the Company's regulated utility customers, Xcel Energy acquires electric capacity and energy as well as natural gas supplies. Included in this operation are certain wholesale trading activities to optimize asset utilization. Xcel Energy is exposed to some level of market and credit risk under its obligation to manage its retail electric distribution and natural gas needs. Xcel Energy enters into derivative instruments to hedge fuel requirements, inventories, excess generation capacity, and purchase power contracts.

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

The adoption of SFAS 133 on Jan. 1, 2001, by Xcel Energy's Utility Subsidiaries did not result in an impact to earnings. However, upon adoption of SFAS 133, PSCo and SPS recorded a net transition gain (loss) of approximately $1.6 million and $(2.6) million, respectively, recorded in other comprehensive income. The impact to other comprehensive income is related to existing cash flow hedges during increasing price conditions.

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

	PSCo			SPS
Net transition gain (loss), Jan. 1, 2001	$	1.6		$	(2.6	)
After-tax net unrealized losses related to derivatives accounted for as hedges		(17.5	)		(2.4	)
After-tax net realized losses on derivative transactions reclassified into earnings		15.8			0.2

Other comprehensive income, June 30, 2001	$	(0.1	)	$	(4.8	)

PSCo's earnings for the first six months of 2001 were increased by approximately $0.2 million (before tax).

Energy and energy related commodities—PSCo is exposed to commodity price variability and credit risk in its generation and retail distribution. In order to manage these commodity price risks, PSCo enters into financial instruments, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps. Derivatives designated to be hedges by PSCo are accounted for as cash flow hedges and recorded as electric fuel and purchased power.

PSCo generally attempts to balance its fixed-price physical and financial purchase and sales commitments in terms of contract volumes, and the timing of performance and delivery obligations. These derivatives do not qualify for hedge accounting and, accordingly, changes in the fair value are reported in earnings.

At June 30, 2001, PSCo had various commodity-related contracts extending through October 2002. PSCo expects to reclassify into earnings during the next twelve months net losses from other comprehensive income of approximately $0.4 million.

Interest rates—To manage interest rate risk, SPS has entered into interest rate swaps that effectively fix the interest payments of certain floating rate debt instruments. Interest rate swap agreements are accounted for as cash flow hedges and recorded as interest expense. SPS expects to reclassify into earnings during the next twelve months net losses from other comprehensive income of approximately $0.7 million.

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

		Hedge ineffectiveness			Derivatives excluded from assessment of hedge effectiveness			Firm commitments no longer qualifying as cash flow hedges
Three months ended June 30, 2001:
	Energy and energy related commodities (PSCo)	$	(1.3	)	$	(0.2	)	$	—
	Interest rates (SPS)		—			—			—
Six months ended June 30, 2001:
	Energy and energy related commodities (PSCo)	$	(1.0	)	$	1.2		$	0.02
	Interest rates (SPS)		—			—			—

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

NSP-Minnesota

Comprehensive income equals net income for the quarters and year-to-date periods ended June 30, 2001 and 2000.

NSP-Wisconsin

Comprehensive income equals net income for the quarters and year-to-date periods ended June 30, 2001 and 2000.

PSCo

The components of total comprehensive income are shown below:

		Three months ended June 30				Six months ended June 30
		2001		2000		2001			2000
		(Thousands of dollars)
Net income		$	66,302	$	60,921	$	173,692		$	129,680
Other comprehensive income:
	Cumulative effect of accounting change-SFAS 133		—		—		1,649			—
	Net gains (losses) on derivatives (see Note 8)		2,725		—		(1,747	)		—

Other comprehensive income			2,725		—		(98	)		—

Comprehensive income		$	69,027	$	60,921	$	173,594		$	129,680

Accumulated comprehensive loss at June 30, 2001, relates to valuation adjustments on derivative financial instruments and hedging activities.

SPS

The components of total comprehensive income are shown below:

		Three months ended June 30					Six months ended June 30
		2001			2000		2001			2000
		(Thousands of dollars)
Net income		$	20,302		$	14,988	$	46,351		$	33,244
Other comprehensive income:
	Cumulative effect of accounting change-SFAS 133		—			—		(2,626	)		—
	Net Gains (losses) on derivatives (see Note 8)		(1,049	)		—		(2,179	)		—

Other comprehensive income			(1,049	)		—		(4,805	)		—

Comprehensive income		$	19,253		$	14,988	$	41,546		$	33,244

Accumulated comprehensive loss at June 30, 2001, relates to valuation adjustments on derivative financial instruments and hedging activities.

REPORTS OF INDEPENDENT PUBLIC ACCOUNTANTS

To Northern States Power Company—Minnesota:

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

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

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

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

ARTHUR ANDERSEN LLP

Minneapolis, Minnesota
August 14, 2001

To Northern States Power Company—Wisconsin:

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

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

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

ARTHUR ANDERSEN LLP

Minneapolis, Minnesota
August 14, 2001

To Public Service Company of Colorado:

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

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

ARTHUR ANDERSEN LLP

Minneapolis, Minnesota
August 14, 2001

To Southwestern Public Service Company:

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

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

ARTHUR ANDERSEN LLP

Minneapolis, Minnesota
August 14, 2001

Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

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

Forward Looking Information

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

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "estimate," "expect," "objective," "outlook," "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 the Xcel Energy's utility subsidiaries to obtain financing on favorable terms;
•: business conditions in the energy industry;
•: competitive factors, including the extent and timing of the entry of additional competition in the markets served by the Utility Subsidiaries of Xcel Energy;
•: unusual weather;
•: state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures, and affect the speed and degree to which competition enters the electric and gas markets;
•: risks associated with the California power markets; and
•: the other risk factors listed from time to time by the Utility Subsidiaries of Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to this Report on Form 10-Q for the quarter ended June 30, 2001.

Market Risks

The Utility Subsidiaries of Xcel Energy are exposed to market risks, including changes in commodity prices, interest rates and currency exchange rates as disclosed in Management's Discussion and Analysis in their annual reports on Form 10-K for the year ended Dec. 31, 2000. The Utility Subsidiaries of Xcel Energy have limited exposure to commodity price and interest rate risk due to cost-based rate regulation. There have been no material changes in the market risk exposures that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2000.

Pending Accounting Changes

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

impairment in accordance with SFAS 121, "Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to be Disposed of." Goodwill should not be amortized after adoption of SFAS 142. Non—amortized intangible assets and goodwill should be tested for impairment annually and on an interim basis if an event or circumstance occurs between annual tests that might reduce the fair value of that asset.

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

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

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

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

SFAS 143 will also affect the accrued plant removal costs for other generation, transmission and distribution facilities. We expect these costs will be reclassified from accumulated depreciation to regulatory liabilities based on the recoverability of these costs in rates. Xcel Energy's Utility Subsidiaries expects to adopt SFAS 143 on Jan. 1, 2003.

NSP-MINNESOTA'S MANAGEMENT'S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

NSP-Minnesota's net income was approximately $98.6 million for the first six months of 2001, compared with approximately $57.1 million for the first six months of 2000.

Conservation Incentive Recovery

Earnings for the second quarter of 2001 were increased due to the reversal of the Minnesota Public Utilities Commission (MPUC) decision to deny NSP-Minnesota recovery of 1998 conservation incentives.

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

In January 2001, the MPUC appealed the lower court decision to the Minnesota Supreme Court. On Feb. 23, 2001, the Minnesota Supreme Court declined to hear the MPUC's appeal. During the second quarter of 2001, NSP-Minnesota filed with the MPUC a plan that carried out, among other things, the court's decision. On June 28, 2001, the MPUC approved the plan and issued an order to that effect shortly thereafter. As a result, the previously recorded liabilities of approximately $41 million (including carrying charges) for potential refunds to customers are no longer required and were reversed as of June 30, 2001.

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

Electric Utility Margins

The following table details the change in electric revenue and margin. Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel clause cost recovery mechanisms for retail customers in several states and the ability to vary wholesale prices with changing market conditions, most fluctuations in energy costs do not affect electric margin. However, the fuel clause cost recovery in the Minnesota, North Dakota and South Dakota jurisdictions does not allow for complete recovery of all purchased power expenses and, therefore, higher purchased power costs, particularly in periods of extreme temperatures, can adversely affect earnings.

		Six months ended June 30
		2001		2000
		(Millions of dollars)
Electric retail, firm wholesale and other revenue		$	1,180	$	1,036
Short-term wholesale revenue			88		76

	Total electric utility revenue		1,268		1,112
Electric retail and firm wholesale fuel and purchased power			423		333
Short-term wholesale fuel and purchased power			62		53

	Total electric utility fuel and purchased power		485		386
Electric retail, firm wholesale and other margin			757		703
Short-term wholesale margin			26		23

	Total electric utility margin	$	783	$	726

Electric revenue increased by approximately $156 million, or 14.1 percent, in the first six months of 2001, compared with the first six months of 2000. Electric margin increased by approximately $57 million, or 8.0 percent, in the first six months of 2001, compared with the first six months of 2000. The increase in retail revenue was primarily due to an increase in purchase power costs recovered in electric rates. Retail electric revenue and margin increased due to sales growth, more favorable weather conditions in the first six months of 2001 and the recovery of conservation incentives. As discussed previously, the reversal of the MPUC decision to deny NSP-Minnesota recovery of 1998 conservation incentives increased retail revenue and margin by $35 million. Additionally, more favorable temperatures during the first six months of 2001 increased retail revenue by approximately $17 million and retail margin by approximately $14 million. Retail revenue and margin were reduced by approximately $5 million in the first six months of 2001 due to a rate reduction in Minnesota agreed to as part of the Xcel Energy merger approval process. The increase in revenue and margin was also

attributed to the shared trading margins from the Joint Operating Agreement (JOA) for the operating utilities of Xcel Energy. The JOA was approved and placed into effect by the Federal Energy Regulatory Commission as part of the NSP/NCE Merger in August 2000.

Gas Utility Margins

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

	Six months ended June 30
	2001			2000
	(Millions of dollars)
Gas revenue	$	446		$	235
Cost of gas purchased and transported		(355	)		(155	)

Gas margin	$	91		$	80

Gas revenue for the first six months of 2001 increased by approximately $211 million, or 89.4 percent, compared with the first six months of 2000, largely due to recovery of the higher cost of gas. Gas margin for the first six months of 2001 increased by $11 million, or 14.3 percent, compared with the first six months of 2000. Cooler winter temperatures increased gas sales in the first six months of 2001, increasing gas revenues by approximately $26 million and gas margins by approximately $9 million.

Non-Fuel Operating Expense and Other Costs

Regulated Other Operating and Maintenance Expense increased by approximately $11 million, or 3.0 percent, for the first six months of 2001, compared with the first six months of 2000. The change is largely due to timing of plant outages.

Depreciation and Amortization Expense increased by approximately $5 million, or 3.3 percent, for the first six months of 2001, compared with the first six months of 2000, primarily due to increased capital additions to utility plant.

Interest expense decreased by approximately $16 million, or 27.1 percent, for the first six months of 2001, compared with the first six months of 2000. The change is largely due to lower average debt levels and lower short-term interest rates.

NSP-WISCONSIN'S MANAGEMENT'S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

NSP-Wisconsin's net income was approximately $16.5 million for the first six months of 2001, compared with approximately $16.8 million for the first six months of 2000.

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 mechanisms of the Wisconsin and

Michigan jurisdictions do not allow for complete recovery of all expenses and, therefore, dramatic changes in costs or periods of extreme temperatures can adversely affect earnings.

		Six months ended June 30
		2001		2000
		(Millions of dollars)
Electric retail, firm wholesale and other revenue		$	218	$	205
Short-term wholesale revenue			0		0

	Total electric utility revenue		218		205
Electric retail and firm wholesale fuel and purchased power			120		106
Short-term wholesale fuel and purchased power			0		0

	Total electric utility fuel and purchased power		120		106
Electric retail, firm wholesale and other margin			98		99
Short-term wholesale margin			0		0

	Total electric utility margin	$	98	$	99

Electric revenue increased by approximately $13 million, or 6.5 percent, in the first six months of 2001, compared with the first six months of 2000. Revenue increased primarily because of rate and cost-sharing mechanisms that passed some of the effects of higher electricity production costs to NSP-Wisconsin's customers. The amount of electricity sold was essentially the same, even though weather during the first six months of 2001 was more favorable for electricity sales than it was during the first six months of 2000. The primary causes of the increase in production expenses were higher generating plant fuel costs and greater and more expensive purchases of power from other parties.

Gas Utility Margins

The following table details the change in gas revenue and margin. The cost of gas tends to vary with amount of gas purchased and unit cost of gas purchases. However, purchased gas cost recovery mechanisms allow NSP-Wisconsin to pass through changes in the cost of natural gas to retail customers, so fluctuations in the cost of gas have little affect on gas margin.

	Six months ended June 30
	2001			2000
	(Millions of dollars)
Gas revenue	$	88		$	53
Cost of gas purchased and transported		(70	)		(38	)

Gas margin	$	18		$	15

Natural gas revenue for the first six months of 2001 increased by $35 million, or 63.9 percent, over the first six months of 2000, mostly due to recovery of the higher natural gas costs for the first six months of 2001. Gas revenue and margin also increased due to more favorable weather conditions, which increased the amount of gas sold.

Non-Fuel Operating Expense and Other Costs

Interest charges were $1.5 million greater during the first six months of 2001 than they were during the first six months of 2000. The increase was primarily because $80 million of new debt had been

issued in October 2000 and part of the proceeds had been used to pay off short-term debt owed to NSP-Minnesota.

PSCo'S MANAGEMENT'S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

PSCo's net income was approximately $173.7 million for the first six months of 2001, compared with approximately $129.7 million for the first six months of 2000.

Postemployment Benefits

Earnings for the second quarter of 2001 were decreased due to a Colorado Supreme Court decision that resulted in a pretax write-off of $23 million of a regulatory asset related to deferred postemployment benefit costs at PSCo. For more information, see Note 2 to the Financial Statements.

Electric Utility Margins

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

		Six months ended June 30
		2001		2000
		(Millions of dollars)
Electric retail and firm wholesale revenue		$	812	$	759
Short-term wholesale revenue			388		75

	Total electric utility revenue		1,200		834
Electric retail and firm wholesale fuel and purchased power			391		337
Short-term wholesale fuel and purchased power			293		59

	Total electric utility fuel and purchased power		684		396
Electric retail and firm wholesale margin			421		422
Short-term wholesale margin			95		16

	Total electric utility margin	$	516	$	438

Electric revenue increased by approximately $366 million, or 43.9 percent, in the first six months of 2001, compared with the first six months of 2000. Electric margin increased by approximately $78 million, or 17.8 percent, in the first six months of 2001, compared with the first six months of 2000. Retail margin was flat for the first six months of 2001. More favorable temperatures during the first six months of 2001 increased retail revenue by approximately $10 million and retail margin by approximately $6 million. Increases in retail margin due to sales growth and more favorable weather conditions were offset by increased fuel and purchased power costs, which are not completely recoverable from customers in Colorado due to various sharing mechanisms. Retail revenue and margin

were reduced by approximately $6 million for the first six months of 2001, due to a rate reduction in Colorado agreed to as part of the Xcel Energy merger approval process.

Short-term wholesale revenue and margin increased due to the expansion of the wholesale marketing operations and favorable market conditions, including strong prices in the western markets, particularly before the establishment of price caps. It is not expected that short-term wholesale margins in the second half of 2001 will be as strong, due to a decline in the forward price curve.

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 in place 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.

	Six months ended June 30
	2001			2000
	(Millions of dollars)
Gas revenue	$	833		$	410
Cost of gas purchased and transported		(665	)		(261	)

Gas margin	$	168		$	149

Gas revenue for the first six months of 2001 increased by approximately $423 million, or 103 percent, compared with the first six months of 2000, due to recovery of the higher cost of gas and sales growth. Gas margin for the first six months of 2001 increased by approximately $19 million, or 12.8 percent, compared with the first six months of 2000. More favorable temperatures during the first six months of 2001 increased gas revenue by approximately $40 million and gas margin by approximately $12 million.

Electric Trading Margins

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

	Six months ended June 30
	2001			2000
	(Millions of dollars)
Trading revenue	$	720		$	147
Trading cost of sales		(690	)		(133	)

Trading margin	$	30		$	14

Trading revenue increased by approximately $573 million and trading margin increased by approximately $16 million for the first six months of 2001, compared with the first six months of 2000. The increase in trading revenue and margin is a result of the expansion of PSCo's electric trading operation and favorable market conditions, including strong prices in the western markets, particularly before the establishment of price caps. It is not expected that trading margins in the second half of 2001 will be as strong, due to a decline in the forward price curve. The trading revenue and margin

were reduced under the provisions of the JOA for the operating utilities of Xcel Energy. The JOA requires certain PSCo trading margins to be shared with NSP-Minnesota and SPS and was approved and placed into effect by the FERC as part of the NSP/NCE Merger in August 2000.

Non-Fuel Operating Expense and Other Costs

Regulated Other Operation and Maintenance Expense increased by approximately $19.2 million, or 10.1 percent, for the first six months of 2001, compared with the first six months of 2000. The change is largely due to increased costs due to customer growth.

Depreciation and Amortization Expense increased by approximately $14 million, or 13.7 percent, for the first six months of 2001, compared with the first six months of 2000, primarily due to increased amortization costs of software and increased capital additions to utility plant.

Interest expense decreased by approximately $13.8 million, or 19.0 percent, for the first six months of 2001, compared with the first six months of 2000. The decrease was primarily due to the maturity of certain First Mortgage Bonds and secured medium term notes. In addition, capitalized interest increased in the first six months of 2001.

Other income and expense for the first six months of 2001 includes a gain on the sale of the Boulder Hydro facility. In March 2001, PSCo sold its Boulder Hydro facility in Colorado and recorded a gain of approximately $11 million (before tax) on this transaction. The gain on this sale has been shared with customers due to its inclusion in the PSCo Electric Earnings Test in Colorado.

SPS' MANAGEMENT'S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

SPS' net income was approximately $46.4 million for the first six months of 2001, compared with approximately $33.2 million for the first six months of 2000.

Extraordinary Item—Electric Utility Restructuring

In the second quarter of 2000, SPS discontinued regulatory accounting under SFAS 71 for the generation portion of its business due to the issuance of a written order by the Public Utilities Commission of Texas (PUCT) in May 2000, addressing the implementation of electric utility restructuring. During the second quarter of 2000, SPS wrote off its generation-related regulatory assets and other deferred costs totaling approximately $19.3 million. This resulted in an after-tax extraordinary charge of approximately $13.7 million. For more information on restructuring, including the reapplication of regulatory accounting under SFAS 71, see Note 4 to the Financial Statements.

Electric Utility Margins

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

recovery does not allow for complete recovery of all variable production expenses and, therefore, higher costs can adversely affect earnings.

		Six months ended June 30
		2001		2000
		(Millions of dollars)
Electric retail, firm wholesale and other revenue		$	699	$	469
Short-term wholesale revenue			2		4

	Total electric utility revenue		701		473
Electric retail and firm wholesale fuel and purchase power			451		231
Short-term wholesale fuel and purchase power			1		3

	Total electric utility fuel and purchase power		452		234
Electric retail, firm wholesale and other margin			248		238
Short-term wholesale margin			1		1

	Total electric utility margin	$	249	$	239

Electric revenue increased by approximately $228 million, or 48.2 percent, for the first six months of 2001, compared with the first six months of 2000. Electric margin increased by approximately $10 million, or 4.2 percent, for the first six months of 2001, compared with the first six months of 2000. Electric revenues increased for the first six months of 2001, compared with the first six months of 2000, largely due to increased recovery of fuel and purchased power costs, particularly the increased cost of natural gas generation. More favorable temperatures during the first six months of 2001 increased retail revenue by approximately $21 million and retail margin by approximately $10 million. Retail revenue and margin were reduced by approximately $3 million for the first six months of 2001, due to rate reductions in Texas and New Mexico agreed to as part of the merger approval process.

Non-Fuel Operating Expense and Other Costs

Regulated Other Operation and Maintenance Expense increased by approximately $8.8 million, or 11.5 percent, for the first six months of 2001, compared with the first six months of 2000. The change is largely due to increased transmission costs from the Southwest Power Pool, (which are offset by increased electric revenue).

Depreciation and Amortization Expense increased by approximately $2.1 million, or 5.4 percent, for the first six months of 2001, compared with the first six months of 2000, primarily due to increased capital additions to utility plant.

Interest expense decreased by approximately $2.2 million, or 8.1 percent, for the first six months of 2001, compared with the first six months of 2000. The change is largely due to lower interest expense due to a shift to more short-term debt and less long-term debt. In addition, capitalized interest increased in the first six months of 2001.

Part II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

In the normal course of business, various lawsuits and claims have arisen against the Utility Subsidiaries of Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. See Notes 4 and 5 of the Financial Statements in this Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 of NSP-Minnesota's, NSP-Wisconsin's, PSCo's and SPS' 2000 Form 10-K for a description of certain legal proceedings presently pending. There are no new significant cases to report against the Utility Subsidiaries of Xcel Energy and there have been no notable changes in the previously reported proceedings, except as set forth below.

NSP-Minnesota

Light Rail Transit (LRT)—On Feb. 16, 2001, NSP-Minnesota filed a suit in the United States District Court in Minneapolis, against the Minnesota Metropolitan Council, Minnesota Department of Transportation, State of Minnesota and the Federal Transit Administration to prevent pave-over of NSP-Minnesota's underground facilities during construction of the LRT system. NSP-Minnesota is also seeking recovery of relocation expenses. State defendants countersued, seeking delay damages and a $330 million surety bond. On May 24, 2001, the District Court issued a preliminary injunction requiring NSP-Minnesota to commence the relocation project and to cooperate with defendants. NSP-Minnesota immediately commenced design engineering for the relocation project in compliance with the preliminary injunction. Xcel Energy has appealed the Judge's Order to relocate. This matter is at the very early stages of litigation. NSP-Minnesota denies the merits of the defendants' countersuits and intends to vigorously defend against their claims.

NSP-Wisconsin

Stubrud Case—On Sept. 25, 2000, NSP-Wisconsin was served with a complaint in Eau Claire County Circuit Court 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 alleges that NSP-Wisconsin acted willfully and wantonly, entitling plaintiffs to treble damages. The plaintiffs allege farm damages of approximately $3.8 million. A ten-day trial commencing December 2, 2002, has been scheduled.

PSCo

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

Item 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

The following Exhibits are filed with this report:

15(a)		Letter from Arthur Andersen LLP regarding unaudited interim information for NSP-Minnesota.
15(b)		Letter from Arthur Andersen LLP regarding unaudited interim information for PSCo.
15(c)		Letter from Arthur Andersen LLP regarding unaudited interim information for SPS.
99.01		Statement pursuant to Private Securities Litigation Reform Act.

(b) Reports on Form 8-K

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

NSP-Minnesota

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

NSP-Wisconsin

None.

PSCo

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

SPS

June 15, 2001 (filed June. 22, 2001)—Item 5 and 7. Other Events and Exhibits. Re: Disclosure of delay for restructuring in SPS' service territory.

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 Aug. 14, 2001.

		NORTHERN STATES POWER CO. (a Minnesota corporation) (Registrant)
		/s/ DAVID E. RIPKA
		David E. Ripka Vice President and Controller
		/s/ EDWARD J. MCINTYRE
		Edward J. McIntyre Vice President and Chief Financial Officer

NORTHERN STATES POWER CO. (A WISCONSIN CORPORATION) SIGNATURES

		NORTHERN STATES POWER CO. (a Wisconsin corporation) (Registrant)
		/s/ DAVID E. RIPKA
		David E. Ripka Vice President and Controller
		/s/ EDWARD J. MCINTYRE
		Edward J. McIntyre 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/ EDWARD J. MCINTYRE
		Edward J. McIntyre Vice President and Chief Financial Officer

SOUTHWESTERN PUBLIC SERVICE CO.

		SOUTHWESTERN PUBLIC SERVICE CO. (Registrant)
		/s/ DAVID E. RIPKA
		David E. Ripka Vice President and Controller
		/s/ EDWARD J. MCINTYRE
		Edward J. McIntyre Vice President and Chief Financial Officer

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Table of Contents
PART 1. FINANCIAL INFORMATION

Item 1. CONSOLIDATED FINANCIAL STATEMENTS

Item 1. LEGAL PROCEEDINGS

Item 6. EXHIBITS AND REPORTS ON FORM 8-K

NORTHERN STATES POWER CO. (A MINNESOTA CORPORATION) SIGNATURES
NORTHERN STATES POWER CO. (A WISCONSIN CORPORATION) SIGNATURES
PUBLIC SERVICE CO. OF COLORADO SIGNATURES
SOUTHWESTERN PUBLIC SERVICE CO.

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Northern States Power 10-Q2001 Q2 Quarterly report

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