Northern States Power 10Q 2000 Q3 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 September 30, 1997

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

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

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. All outstanding common stock is owned beneficially and of record by Xcel Energy Inc., a Minnesota corporation. Shares outstanding at Oct. 31, 2000:


Northern States Power Company (a Minnesota Corporation)	Common Stock, $0.01 par value	1,000,000 Shares
Northern States Power Company (a Wisconsin Corporation)	Common Stock, $100 par value	933,000 Shares
Public Service Company of Colorado	Common Stock, $0.01 par value	100 Shares
Southwestern Public Service Company	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		32
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 Company, a Minnesota corporation (NSP-Minnesota), Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin), Public Service Company of Colorado (PSCo) and Southwestern Public Service Company (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.

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

PART 1. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

			Three Months Ended Sept. 30					Nine Months Ended Sept. 30
			2000			1999		2000			1999
Operating revenues:
	Electric utility		$	696,290		$	723,268	$	1,807,919		$	1,776,444
	Gas utility			64,741			43,976		300,011			241,781

		Total revenues		761,031			767,244		2,107,930			2,018,225
Operating expenses:
	Electric fuel and purchased power			251,469			272,015		637,307			648,060
	Cost of gas sold and transported			44,474			28,767		199,961			148,182
	Other operating and maintenance expenses			175,871			173,412		555,847			539,497
	Depreciation and amortization			80,743			77,775		241,992			230,795
	Taxes (other than income taxes)			54,691			54,364		158,840			160,382
	Special charges (see Note 2)			59,059			—		59,059			—

		Total operating expenses		666,307			606,333		1,853,006			1,726,916

Operating income				94,724			160,911		254,924			291,309
Other income (deductions)—net				(870	)		1,519		(763	)		516
Interest charges and financing costs:
	Interest charges—net of amount capitalized			32,681			27,177		93,487			75,119
	Distributions on redeemable preferred securities of subsidiary trust			3,938			3,937		11,813			11,813

		Total interest charges and financing costs		36,619			31,114		105,300			86,932

Income before income taxes				57,235			131,316		148,861			204,893
Income taxes				32,072			52,066		66,590			77,509

Net income			$	25,163		$	79,250	$	82,271		$	127,384

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

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

			Nine Months Ended Sept. 30
			2000			1999
Operating activities:
	Net income		$	82,271		$	127,384
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization		254,214			243,744
		Nuclear fuel amortization		32,937			37,783
		Deferred income taxes		(3,477	)		(25,452	)
		Amortization of investment tax credits		(6,149	)		(6,065	)
		Allowance for equity funds used during construction		1,025			(1,455	)
		Conservation incentive accrual adjustment—noncash		19,966			35,035
		Change in accounts receivable		15,419			32,890
		Change in inventories		(16,994	)		(10,944	)
		Change in other current assets		52,938			6,892
		Change in accounts payable		36,605			(27,692	)
		Change in other current liabilities		(22,262	)		21,125
		Change in other assets and liabilities		(47,196	)		26,491

		Net cash provided by operating activities		399,297			459,736
Investing activities:
	Capital/construction expenditures			(264,327	)		(232,430	)
	Allowance for equity funds used during construction			(1,025	)		1,455
	Investments in external decommissioning fund			(38,921	)		(32,649	)
	Other investments—net			(6,565	)		(6,454	)

		Net cash used in investing activities		(310,838	)		(270,078	)
Financing activities:
	Short-term borrowings—net			203,150			203,684
	Proceeds from issuance of long-term debt—net			96,123			264,970
	Repayment of long-term debt, including reacquisition premiums			(97,036	)		(203,056	)
	Capital distributions to parent			(222,376	)		(291,232	)

		Net cash used in financing activities		(67,293	)		(164,396	)

	Net increase in cash and cash equivalents			21,166			25,262
	Cash and cash equivalents at beginning of period			11,344			20,125

	Cash and cash equivalents at end of period		$	32,510		$	45,387

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

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

			Sept. 30, 2000			Dec. 31, 1999
ASSETS
Current assets:
	Cash and cash equivalents		$	32,510		$	11,344
	Accounts receivable—net of allowance for bad debts of $5,189 and $5,503, respectively			331,907			347,326
	Accrued unbilled revenues			101,111			122,493
	Materials and supplies inventories at average cost			104,307			101,678
	Fuel and gas inventories at average cost			65,880			51,514
	Prepayments and other			18,584			50,141

		Total current assets		654,299			684,496

Property, plant and equipment, at cost:
	Electric utility			6,419,618			6,320,214
	Gas utility			645,594			629,158
	Other and construction work-in-progress			512,705			441,141

		Total property, plant and equipment		7,577,917			7,390,513
	Less: accumulated depreciation			(4,043,859	)		(3,855,225	)
	Nuclear fuel—net of accumulated amortization of $956,274 and $923,336, respectively			89,075			102,727

		Net property, plant and equipment		3,623,133			3,638,015

Other assets:
	Nuclear decommissioning fund investments			559,171			517,129
	Other investments			26,305			25,341
	Regulatory assets			220,443			208,176
	Deferred charges and other			137,211			94,549

		Total other assets		943,130			845,195

		Total Assets	$	5,220,562		$	5,167,706

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	248,174		$	255,718
	Short-term debt			576,190			420,193
	Accounts payable			203,150			203,684
	Accounts payable to affiliates			44,414			7,268
	Taxes accrued			157,616			162,748
	Other			127,317			177,541

		Total current liabilities		1,356,861			1,227,152

Deferred credits and other liabilities:
	Deferred income taxes			665,920			681,431
	Deferred investment tax credits			93,505			100,105
	Regulatory liabilities			485,129			439,717
	Benefit obligations and other			144,872			146,620

		Total deferred credits and other liabilities		1,389,426			1,367,873

Long-term debt				1,210,142			1,186,586
Mandatorily redeemable preferred securities of subsidiary trust				200,000			200,000
Common stock and paid-in capital				125,561			145,613
Retained earnings				965,186			1,052,088
Leveraged shares held by ESOP at cost				(26,614	)		(11,606	)

		Total common stockholder equity		1,064,133			1,186,095

Commitments and contingencies (see Note 5)
		Total Liabilities and Equity	$	5,220,562		$	5,167,706

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

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

			Three Months Ended Sept. 30				Nine Months Ended Sept. 30
			2000		1999		2000		1999
Operating revenues:
	Electric utility		$	111,418	$	109,344	$	315,986	$	309,149
	Gas utility			10,284		8,634		63,672		54,872

	Total revenues			121,702		117,978		379,658		364,021
Operating expenses:
	Electric fuel and purchased power			53,844		57,176		159,949		157,134
	Cost of gas sold and transported			7,051		5,138		44,739		35,803
	Other operating and maintenance expenses			25,827		25,370		75,693		74,041
	Depreciation and amortization			10,422		10,485		30,759		31,396
	Taxes (other than income taxes)			3,801		3,759		11,691		11,258
	Special charges (see Note 2)			10,833		—		10,833		—

		Total operating expenses		111,778		101,928		333,664		309,632

Operating income				9,924		16,050		45,994		54,389
Other income (deductions)—net				304		249		1,054		172
Total interest charges and financing costs				4,731		4,572		14,077		13,692

Interest charges and financing costs:
Income before income taxes				5,497		11,727		32,971		40,869
Income taxes				3,654		4,863		14,332		16,501

Net income			$	1,843	$	6,864	$	18,639	$	24,368

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

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

				Nine Months Ended Sept. 30
				2000			1999
Operating activities:
	Net income			$	18,639		$	24,368
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			31,473			32,086
		Deferred income taxes			1,089			702
		Amortization of investment tax credits			(620	)		(629	)
		Allowance for equity funds used during construction			(252	)		(195	)
		Distributions in excess of (less than) equity earnings of unconsolidated affiliates			(259	)		(223	)
		Change in accounts receivable			4,841			6,011
		Change in inventories			102			4,808
		Change in other current assets			8,485			12,364
		Change in accounts payable			(1,674	)		777
		Change in other current liabilities			4,031			(2,262	)
		Change in other assets and liabilities			(677	)		559

			Net cash provided by operating activities		65,178			78,366

Investing activities:
	Capital/construction expenditures				(72,109	)		(59,524	)
	Allowance for equity funds used during construction				252			195
	Other investments—net				536			(985	)

			Net cash provided (used) for investing activities		(71,321	)		(60,314	)

Financing activities:
	Short-term borrowings—net				(3,600	)		2,900
	Issuance of common stock to parent				29,977			—
	Dividends paid to parent				(20,254	)		(20,248	)

			Net cash provided (used) for financing activities		6,123			(17,348	)

	Net (decrease) increase in cash and cash equivalents				(20	)		704
	Cash and cash equivalents at beginning of period				51			51

	Cash and cash equivalents at end of period			$	31		$	755

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

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

			Sept. 30, 2000			Dec. 31, 1999
ASSETS
Current assets:
	Cash and cash equivalents		$	31		$	51
	Accounts receivable—net of allowance for bad debts of $1,308 and $1,215, respectively			32,478			37,320
	Accrued unbilled revenues			13,662			21,768
	Materials and supplies inventories at average cost			6,850			7,068
	Fuel and gas inventories at average cost			7,582			7,465
	Prepayments and other			12,697			13,076

		Total current assets		73,300			86,748

Property, plant and equipment, at cost:
	Electric utility			1,035,884			990,527
	Gas utility			121,294			117,202
	Other and construction work-in-progress			144,354			132,591

		Total property, plant and equipment		1,301,532			1,240,320
	Less: accumulated depreciation			(510,643	)		(487,549	)

		Net property, plant and equipment		790,889			752,771

Other assets:
	Other investments			9,019			9,295
	Regulatory assets			36,838			39,252
	Deferred charges and other			21,781			19,037

		Total other assets		67,638			67,584

		Total Assets	$	931,827		$	907,103

LIABILITIES AND EQUITY
Current Liabilities:
	Short-term debt—notes payable to affiliate		$	77,200		$	80,800
	Accounts payable			26,912			21,636
	Accounts payable to affiliates			8,256			18,338
	Taxes accrued			—			829
	Other			20,641			15,936

		Total current liabilities		133,009			137,539

Deferred credits and other liabilities:
	Deferred income taxes			113,248			111,772
	Deferred investment tax credits			16,658			17,281
	Regulatory liabilities			20,310			21,726
	Benefit obligations and other			31,224			29,835

		Total other liabilities		181,440			180,614

Long-term debt				232,016			231,950
Common stock and paid-in capital				126,718			96,741
Retained earnings				258,644			260,259

		Total common stockholder equity		385,362			357,000

Commitments and Contingent Liabilities (see Note 5)
		Total Liabilities and Equity	$	931,827		$	907,103

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

PUBLIC SERVICE COMPANY OF COLORADO
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(Thousands of Dollars)

			Three Months Ended Sept. 30				Nine Months Ended Sept. 30
			2000		1999		2000		1999
Operating revenues:
	Electric utility		$	616,124	$	400,892	$	1,471,450	$	1,155,904
	Gas utility			91,522		82,471		501,103		477,537

		Total revenues		707,646		483,363		1,972,553		1,633,441
Operating expenses:
	Electric fuel and purchased power			378,751		174,587		781,474		507,524
	Cost of gas sold and transported			35,024		34,900		296,015		295,462
	Other operating and maintenance expenses			100,088		93,098		290,525		289,646
	Depreciation and amortization			49,921		50,332		152,171		147,694
	Taxes (other than income taxes)			19,340		17,527		61,149		64,609
	Special charges (see Note 2)			64,817		—		64,817		—

		Total operating expenses		647,941		370,444		1,646,151		1,304,935

Operating income				59,705		112,919		326,402		328,506
Other income (deductions)—net				1,807		951		10,850		5,173
Interest charges and financing costs:
	Interest charges—net of amount capitalized			38,393		37,149		111,401		104,617
	Distributions on redeemable preferred securities of subsidiary trust			3,800		3,800		11,400		11,400

		Total interest charges and financing costs		42,193		40,949		122,801		116,017

Income before income taxes				19,319		72,921		214,451		217,662
Income taxes				11,472		23,172		76,925		67,154

Net income			$	7,847	$	49,749	$	137,526	$	150,508

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

PUBLIC SERVICE COMPANY OF COLORADO
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(Thousands of Dollars)

			Nine Months Ended Sept. 30
			2000			1999
Operating activities:
	Net income		$	137,526		$	150,508
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization		157,674			154,207
		Deferred income taxes		6,956			8,333
		Amortization of investment tax credits		(3,370	)		(3,582	)
		Change in accounts receivable		(31,100	)		2,205
		Change in inventories		(4,106	)		(14,125	)
		Change in other current assets		(25,896	)		46,425
		Change in accounts payable		120,922			(13,384	)
		Change in other current liabilities		17,209			(4,860	)
		Change in other assets and liabilities		3,740			(10,073	)

		Net cash provided by operating activities		379,555			315,654
Investing activities:
	Capital/construction expenditures			(230,122	)		(370,148	)
	Proceeds from disposition of property, plant and equipment			8,350			13,242
	Payment received of notes receivable from affiliate			75,000			—
	Other investments—net			1,450			11,189

		Net cash used in investing activities		(145,322	)		(345,717	)
Financing activities:
	Short-term borrowings—net			(46,018	)		(6,495	)
	Proceeds from issuance of long-term debt—net			97,314			243,270
	Repayment of long-term debt, including reacquisition premiums			(172,293	)		(72,932	)
	Dividends paid to parent			(150,180	)		(139,089	)

		Net cash (used in) provided by financing activities		(271,177	)		24,754

	Net decrease in cash and cash equivalents			(36,944	)		(5,309	)
	Cash and cash equivalents at beginning of period			51,731			19,926

	Cash and cash equivalents at end of period		$	14,787		$	14,617

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

PUBLIC SERVICE COMPANY OF COLORADO
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(Thousands of Dollars)

			Sept. 30, 2000			Dec. 31, 1999
ASSETS
Current assets:
	Cash and cash equivalents		$	14,787		$	51,731
	Accounts receivable—net of allowance for bad debts of $3,125 and $2,533, respectively			230,404			199,304
	Accrued unbilled revenues			262,170			220,330
	Recoverable purchased gas and electric energy costs			37,881			42,697
	Materials and supplies inventories at average cost			44,323			53,984
	Fuel and gas inventories at average cost			103,580			89,813
	Prepayments and other			42,714			46,292

		Total current assets		735,859			704,151

Property, plant and equipment, at cost:
	Electric utility			4,867,406			4,629,092
	Gas utility			1,330,672			1,289,995
	Other and construction work-in-progress			779,024			827,273

		Total property, plant and equipment		6,977,102			6,746,360
	Less: accumulated depreciation			(2,526,944	)		(2,373,824	)

		Net property, plant and equipment		4,450,158			4,372,536

Other assets:
	Note receivable from affiliate			117,620			192,620
	Other investments			11,229			12,679
	Regulatory assets			222,703			236,251
	Deferred charges and other			67,476			70,705

		Total other assets		419,028			512,255

		Total Assets	$	5,605,045		$	5,588,942

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	172,013		$	132,823
	Short-term debt			310,175			356,192
	Accounts payable			396,350			331,283
	Accounts payable to affiliates			61,463			5,608
	Taxes accrued			79,385			67,030
	Dividends payable			30,606			44,575
	Recovered electric energy costs			25,001			11,873
	Other			151,199			159,471

		Total current liabilities		1,226,192			1,108,855

Deferred credits and other liabilities:
	Deferred income taxes			560,386			555,829
	Deferred investment tax credits			85,916			89,286
	Regulatory liabilities			90,440			80,819
	Benefit obligations and other			74,604			77,309

		Total deferred credits and other liabilities		811,346			803,243

Long-term debt				1,611,308			1,721,959
Mandatorily redeemable preferred securities of subsidiary trust				194,000			194,000
Common stock and paid-in capital				1,414,835			1,414,835
Retained earnings				347,364			346,050

		Total common stockholders' equity		1,762,199			1,760,885
Commitments and contingencies (see Note 5)

		Total Liabilities and Equity	$	5,605,045		$	5,588,942

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

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

			Three Months Ended Sept. 30					Nine Months Ended Sept. 30
			2000			1999		2000			1999
Electric operating revenues			$	319,530		$	290,587	$	792,404		$	717,253
Operating expenses:
	Electric fuel and purchased power			162,486			148,086		396,814			344,623
	Other operating and maintenance expenses			38,827			29,910		115,677			97,572
	Depreciation and amortization			19,345			18,450		58,063			55,357
	Taxes (other than income taxes)			10,988			13,208		34,843			39,079
	Special charges (see Note 2)			19,943			—		19,943			—

		Total operating expenses		251,589			209,654		625,340			536,631

Operating income				67,941			80,933		167,064			180,622
Other income (deductions)—net				2,003			2,349		8,238			6,809
Interest charges and financing costs:
	Interest charges—net of amount capitalized			14,246			13,765		41,331			39,915
	Distributions on redeemable preferred securities of subsidiary trust			1,963			1,963		5,888			5,888

		Total interest charges and financing costs		16,209			15,728		47,219			45,803

Income before income taxes and extraordinary item				53,735			67,554		128,083			141,628
Income taxes				21,844			25,020		49,290			52,868

Income before extraordinary item				31,891			42,534		78,793			88,760
Extraordinary item, net of tax (see Note 4)				(5,302	)		—		(18,960	)		—

Net income			$	26,589		$	42,534	$	59,833		$	88,760

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

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

				Nine Months Ended Sept. 30
				2000			1999
Operating activities:
	Net income			$	59,833		$	88,760
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			60,598			58,301
		Deferred income taxes			37,312			13,868
		Amortization of investment tax credits			(188	)		(188	)
		Allowance for equity funds used during construction			1			(1,075	)
		Extraordinary item (see Note 4)			18,960			—
		Change in accounts receivable			1,383			(13,851	)
		Change in inventories			5,556			(1,117	)
		Change in other current assets			(156,346	)		(51,546	)
		Change in accounts payable			45,267			24,940
		Change in other current liabilities			839			(26,690	)
		Change in other assets and liabilities			(22,604	)		(13,318	)

			Net cash provided by operating activities		50,611			78,084
Investing activities:
	Capital/construction expenditures				(70,338	)		(88,247	)
	Allowance for equity funds used during construction				(1	)		1,075
	Proceeds from disposition of property, plant and equipment				(2,818	)		(1,719	)
	Other investments—net				(6,316	)		(126	)

			Net cash used in investing activities		(79,473	)		(89,017	)
Financing activities:
	Short-term borrowings—net				477,023			9,229
	Proceeds from issuance of long-term debt—net				—			99,846
	Repayment of long-term debt, including reacquisition premiums				(380,267	)		(24,733	)
	Dividends paid to parent				(65,699	)		(62,375	)

			Net cash provided by financing activities		31,057			21,967

	Net increase in cash and cash equivalents				2,195			11,034
	Cash and cash equivalents at beginning of period				1,532			1,350

	Cash and cash equivalents at end of period			$	3,727		$	12,384

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

SOUTHWESTERN PUBLIC SERVICE COMPANY
BALANCE SHEETS (UNAUDITED)
(Thousands of Dollars)

			Sept. 30, 2000			Dec. 31, 1999
ASSETS
Current assets:
	Cash and cash equivalents		$	3,727		$	1,532
	Accounts receivable—net of allowance for bad debts of $353 and $682, respectively			82,544			83,928
	Accrued unbilled revenues			90,018			44,631
	Recoverable electric energy costs.			94,393			1,948
	Materials and supplies inventories at average cost			12,475			18,035
	Fuel and gas inventories at average cost			2,296			2,292
	Prepayments and other			2,990			4,324

		Total current assets		288,443			156,690

Property, plant and equipment, at cost:
	Electric utility			2,866,895			2,802,077
	Other and construction work-in-progress			99,833			95,477

		Total property, plant and equipment		2,966,728			2,897,554
	Less: accumulated depreciation			(1,179,482	)		(1,123,739	)

		Net property, plant and equipment		1,787,246			1,773,815

Other assets:
	Notes receivable from affiliate			119,036			119,036
	Other investments			12,262			5,946
	Regulatory assets			79,228			101,419
	Prepaid pension asset			56,101			40,087
	Deferred charges and other			22,938			22,383

		Total other assets		289,565			288,871

		Total Assets	$	2,365,254		$	2,219,376

LIABILITIES AND EQUITY
Current liabilities:
	Short-term debt		$	654,768		$	177,746
	Accounts payable			101,998			73,613
	Accounts payable to affiliates			19,829			2,947
	Taxes accrued			2,383			23,486
	Interest accrued			492			17,223
	Dividends payable			—			20,963
	Other			77,481			32,690

		Total current liabilities		856,951			348,668

Deferred credits and other liabilities:
	Deferred income taxes			366,167			376,245
	Deferred investment tax credits			4,780			4,969
	Benefit obligations and other			34,374			22,236

		Total deferred credits and other liabilities		405,321			403,450

Long-term debt				226,502			605,875
Mandatorily redeemable preferred securities of subsidiary trusts				100,000			100,000
Common stock and paid-in capital				353,099			353,099
Retained earnings				423,381			408,284

		Total common stockholders' equity		776,480			761,383
Commitments and contingencies (see Note 5)				—			—

		Total Liabilities and Equity	$	2,365,254		$	2,219,376

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS (collectively referred to as the Utility Subsidiaries of Xcel Energy) as of Sept. 30, 2000, and Dec. 31, 1999, the results of its operations for the three and nine months ended Sept. 30, 2000 and 1999, and its cash flows for the nine months ended Sept. 30, 2000 and 1999. Due to the seasonality of electric and gas sales of the Utility Subsidiaries of Xcel Energy, quarterly and year-to-date results are not necessarily an appropriate base from which to project annual results.

The accounting policies of NSP-Minnesota are set forth in Note 1 to the financial statements of its Form 10. The accounting policies of 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, 1999. The following notes should be read in conjunction with such policies and other disclosures in the Form 10 and the Form 10-Ks.

1. Merger to Create Xcel Energy

On Aug. 18, 2000, New Century Energies (NCE) and Northern States Power Company (NSP) merged and formed Xcel Energy Inc. Xcel Energy, a Minnesota corporation, is a registered holding company under the Public Utility Holding Company Act of 1935. 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.

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. 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

Consistent with pooling accounting requirements, upon consummation of the merger in the third quarter of 2000, Xcel Energy expensed all merger-related costs. During the third quarter of 2000, Xcel Energy recognized pretax special charges totaling $201 million in merger-related costs. During the third quarter of 2000, an allocation of $159 million of these merger costs was made to the Utility Subsidiaries of Xcel Energy consistent with prior regulatory filings and is reported on the accompanying financial statements as special charges.

The pretax charges included $49 million related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE. These transaction costs include investment banker fees, legal and regulatory approval costs, and expenses for support of and assistance with planning and completing the merger transaction.

Also included were $110 million of pretax charges pertaining to incremental costs of transition and integration activities associated with merging NSP and NCE to begin operations as Xcel Energy. These transition costs include approximately $68 million for severance and related expenses associated with staff reductions of 656 employees, most of whom were released in September and October 2000. Other transition and integration costs include amounts incurred for facility consolidation, systems integration, regulatory transition, merger communications and operations integration assistance.

In addition to the special charges recorded in third quarter 2000, Xcel Energy anticipates approximately $30 million to be incurred in the fourth quarter of 2000 for additional merger transition,

integration and severance activities that are expected to occur prior to year-end. Management expects the majority of its merger-related transition and integration activities to be completed by early 2001 so that Xcel Energy can fully realize in 2001 and future years the operating synergies anticipated from the merger of NSP and NCE. Once incurred, an allocation of fourth quarter merger costs will be made to Xcel Energy's Utility Subsidiaries.

3. Business Developments

NSP-Minnesota

Nuclear Management Company (NMC)—During 1999, NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin Public Service Corp. and Alliant Energy established the NMC. The four companies operate seven nuclear units at five sites, with a total generation capacity exceeding 3,650 megawatts.

During the second quarter of 2000, the Nuclear Regulatory Commission (NRC) approved requests by NMC's four affiliated utilities to transfer operating authority for their five nuclear plants to NMC. NRC action paves the way for NMC to assume management of operations and maintenance at the five plants. The NRC also is considering requests from three intervenors for hearings regarding NSP-Minnesota's application. NMC responsibilities will include oversight of on-site dry storage facilities for used nuclear fuel at the Point Beach and Prairie Island nuclear plants. Utility plant owners will continue to own the plants, control all energy produced by the plants and retain responsibility for nuclear liability insurance and decommissioning costs. The transfer of operating authority will formally establish NMC as an operating company, with a senior management team focused on sharing best practices. Existing personnel will continue to provide day-to-day plant operations, with the additional benefit of tapping into ideas from all NMC-operated plants for improved safety, reliability and operational performance.

During the third quarter of 2000, NMC and Consumers Energy (CE) reached a tentative agreement, subject to the approval of the CE Board of Directors, for NMC to operate CE's 789-megawatt Palisades nuclear plant in Covert, Mich. The addition of Palisades would give NMC 4,500 megawatts of generation, making it the sixth largest operator of nuclear plants in the United States.

Black Dog Plant Project—During June 2000, the Minnesota Public Utilities Commission (MPUC) issued a certificate of need for the Black Dog plant repowering project. The project involves converting two of Black Dog's four electric generating units from coal to natural gas, a move that will result in greater operating efficiency and cleaner power production, including a reduction in NSP-Minnesota's air emissions. Using natural gas combined-cycle technology, output from the two units will be boosted by more than 100 megawatts. Other key regulatory approvals are needed from the Minnesota Environmental Quality Board and Pollution Control Agency. NSP-Minnesota expects to receive final approvals in the second half of 2000 and then immediately begin construction. The project should be completed prior to the summer of 2002.

NSP-Wisconsin

New Customer—In 2000, NSP-Wisconsin was selected to supply electricity and operate the distribution system at Fort McCoy, a regional Army training center near Sparta, Wis. There are more than 1,000 buildings on 60,000 acres. NSP-Wisconsin will begin providing service under the new contract in the fall of 2000.

Wheaton Plant Conversion—In 2000 NSP-Wisconsin converted units 1 and 3 of the Wheaton generating plant to operate on both oil and natural gas. Previously the units operated on oil exclusively. Two other units at Wheaton were converted in 1997. The conversions were prompted by an opportunity to decrease the cost of producing electricity and reduce plant emissions.

PSCo

Colorado Natural Fuels Co. LLC—During the third quarter of 2000, PSCo sold Colorado Natural Fuels Co. LLC to Blue Energy & Technologies LLC, a new, multi-dimensional natural gas vehicle company. PSCo recognized a loss of $1.7 million on the sale. The transaction includes a network of 35 public natural gas fueling stations and related operations in Colorado and Wyoming. PSCo partnered with Colorado Interstate Gas to form Natural Fuels Corp. as a nonregulated subsidiary in 1990 in response to the growing demand for alternatives to gasoline and diesel vehicles.

4. Regulation and Rate Matters

NSP-Minnesota

Conservation Recovery—NSP-Minnesota has had a 4.1 percent conservation rate surcharge in place since 1998, pending resolution of the conservation incentive recovery issue. On July 31, 2000, the MPUC approved NSP-Minnesota's request to prospectively reduce the surcharge level to 0.68 percent (consistent with current costs to be recovered) and to refund cumulative overcollections of approximately $24 million. The refund will occur during December 2000. This refund does not include the 1998 conservation incentive amounts still under appeal. Although cash flows will be reduced, NSP-Minnesota does not expect any earnings impact from these actions due to accruals previously recorded.

Fuel Clause Adjustment (FCA)—In June 2000, the MPUC approved a change under which bills received by NSP-Minnesota's electricity customers will more accurately reflect energy costs on a timely basis. The FCA is a mechanism that allows NSP-Minnesota to bill customers for the actual cost of fuel used to generate electricity at its plants and energy purchased from other suppliers. Previously, the adjustment reflected prior period costs, and it would take approximately three months for customer bills to reflect higher, or lower, fuel costs incurred by NSP-Minnesota. Under the new method, NSP-Minnesota bases the customer billing adjustment on projected energy costs for the current month, and corrects in a subsequent month any differences between projected costs and actual costs incurred. This improved matching between costs and usage should encourage customers to take appropriate steps to reduce energy use during peak periods—when costs are at their highest—while giving appropriate price signals when costs are lower during off-peak periods. NSP-Minnesota implemented the revised fuel clause adjustment with July 2000 billings.

Energy Cost Recovery—On April 3, 2000, the Minnesota Office of Attorney General (OAG) filed a petition with the MPUC asking the MPUC to initiate an investigation of NSP-Minnesota's fuel and purchased energy cost recoveries under the FCA provisions of NSP's tariffs. The OAG alleged NSP-Minnesota could be improperly diverting low-cost NSP-Minnesota generation supplies to the wholesale market to increase profits, while recovering higher-cost energy purchases through the FCA. NSP-Minnesota contends that it has followed the appropriate FCA rules and regulations. On July 20, 2000, the MPUC issued an order in which it indicated that the record before the MPUC did not reflect any specific allegations of wrongdoing. However, the MPUC instructed NSP-Minnesota and the OAG

to resolve any concerns and file a report with the MPUC. It is currently anticipated that a report or update will be filed with the MPUC in January 2001.

North Dakota Rate Case—On October 2000, NSP-Minnesota filed a natural gas rate increase request with the North Dakota Public Service Commission. The request seeks to increase natural gas rates by approximately 3.3 percent or $1.4 million annually.

NSP-Wisconsin

Electric Transmission—In April 1998, Wisconsin state legislators enacted a law that includes provisions that require the Public Service Commission of Wisconsin (PSCW) to order a public utility that owns transmission facilities in Wisconsin to transfer control of its transmission facilities to an Independent System Operator (ISO), or divest its interest in its transmission facilities to an Independent Transmission Company (ITC), if the public utility has not already transferred control to an ISO or divested to an ITC by June 30, 2000. NSP joined the Midwest ISO (MISO) in late 1999 and filed for PSCW and Federal Energy Regulatory Commission (FERC) approval in March 2000. The MISO is not expected to be operational until November 2001. On June 30, 2000, the PSCW issued an order that effectively waived the June 30, 2000, deadline for the state's five major utilities, including NSP-Wisconsin, to relinquish transmission system control. In October 2000, the PSCW issued an order authorizing NSP-Wisconsin's transfer of operating control of its transmission system to the MISO.

Construction Authorization—In 1996, NSP and Dairyland Power Cooperative (DPC) proposed building an electric transmission system between NSP-Minnesota's Chisago County substation in eastern Minnesota and DPC's Apple River substation in northwestern Wisconsin in response to a need for additional reliability and capacity in both regions. During the second quarter of 1999, the PSCW granted permission to build the Wisconsin portion of the system. The City of St. Croix Falls, Wis., and the Concerned River Valley Citizens advocacy group (the parties) filed lawsuits against the PSCW appealing the decision. Approval from the Minnesota Environmental Quality Board (MEQB) was delayed to address additional discovery by the parties. In early 2000, NSP and DPC agreed with the parties to enter into mediation. In September 2000, the cities of Taylors Falls, Minn. and St. Croix Falls, Wis., signed a settlement agreement recommending a lower voltage, 161-kilovolt line. As part of the agreement, NSP-Minnesota and DPC filed with the MEQB to withdraw their application before the MEQB, which was filed on Sept. 29, 2000. Applications for the revised project will be filed with local permitting authorities in Minnesota, and the utilities will seek a revision of an existing order from the PSCW. The earliest construction could begin is 2003.

Temporary Fuel Cost Surcharge—On Feb. 14, 2000, NSP-Wisconsin filed an application with the PSCW to increase electric rates to recover higher fuel costs. This application was subsequently updated with additional information on March 17, 2000. The increase is primarily the result of higher purchased power costs than were anticipated in base rates. The surcharge factor is expected to increase revenues by approximately $6.5 million in 2000 and represents an average increase for all customer classes of approximately 3 percent. The PSCW issued its order granting the surcharge on May 2, 2000. The surcharge factor is expected to be effective through Dec. 31, 2001.

Reliability 2000—During the summer of 1999, Wisconsin state lawmakers passed "Reliability 2000" legislation which included steps necessary to further progress toward a restructured industry, eventually including allowing retail customers to choose their electric supplier. One of the provisions of the legislation establishes a "public benefits" fund, to be administered by the State of Wisconsin, which will use money collected from Wisconsin utilities' customers to pay for low-income assistance, conservation

programs, and renewable energy and environmental research programs. This fund will increase the amount of money that must be collected from NSP-Wisconsin's customers. NSP-Wisconsin began collecting the public benefits surcharge from its Wisconsin customers in October 2000.

Michigan Restructuring—On June 3, 2000, Michigan's Gov. Engler signed Act 141, the "Customer Choice and Electricity Reliability Act," into law. The passage of Act 141 means there will be customer choice for all customers in Michigan, including NSP-Wisconsin's customers in the Upper Peninsula, starting Jan. 1, 2002. Key elements of the law that may affect NSP-Wisconsin and its approximately 10,000 electric customers include developing reliability standards and fuel disclosure standards, codes of conduct, a state-wide customer choice education program and an Upper Peninsula Market Power Study. Act 141 also contains a number of consumer protection provisions dealing with "cramming," "slamming" and low income energy assistance. NSP-Wisconsin filed its restructuring plan in October 2000 and expects to file its unbundled rates by June 2001. The five percent rate reduction and rate freeze ordered in Act 141 does not apply to NSP-Wisconsin or other utilities with less than 1 million customers in Michigan.

PSCo

Performance Based Regulatory Plan—The Colorado Public Utilities Commission (CPUC) has established a performance based regulatory plan under which PSCo operates. The major components of this regulatory plan include the following:

•: an annual electric earnings test with the sharing of earnings in excess of an 11 percent return on equity for the calendar years 1997-2001;
•: a Quality Service Plan (QSP), which provides for refunds to customers if PSCo does not achieve certain performance measures relating to electric reliability and customer service; and
•: an incentive cost adjustment (ICA), which provides for the sharing of energy costs and savings relative to an annual target cost/delivered kilowatt.

PSCo regularily monitors and records as necessary an estimated customer refund obligation under the earnings test. In April of each year following the measurement period, PSCo files its proposed rate adjustment under the PBRP. The CPUC conducts proceedings to review and approve these rate adjustments annually. During the nine months ended Sept. 30, 2000, PSCo has recorded an estimated customer refund obligation of approximately $12 million (excluding adjustments to true up prior year estimates). In June 2000, an administrative law judge (ALJ) issued a recommendation on the unresolved issues related to the 1998 earnings test. PSCo filed its brief on exceptions with the CPUC, asking the CPUC to disregard the ALJ's recommendation and to issue an order adopting PSCo's position. A final CPUC decision related to the refund obligation for 1998 is pending. The procedural schedule for the 1999 earnings test has been established, with hearings set for February 2001.

Transmission Line—On Oct. 31, 2000, PSCo filed a request with the CPUC for a Certificate of Public Convenience and Necessity to construct a 345 kilovolt transmission line from Lamar, Colo., to Holcomb, Kan., and to construct a high-voltage, direct current converter at the line's Lamar terminus. This transmission project is the second phase of a two-phase transmission interconnection project that will, if approved, ultimately connect PSCo with SPS. Hearings have not yet been scheduled.

Underground Storage Facility—On April 14, 2000, PSCo filed an application with the CPUC requesting authority to shut down and abandon its Leyden Natural Gas Underground Storage Facility

located northwest of the City of Arvada, Colo., during 2001, after 40 years of operation. The application seeks approval of a formal decommissioning plan, which has an estimated cost of approximately $8.6 million. In June 2000, an ALJ determined that the notice was adequate and the application was proper. Hearings and testimony are scheduled for the fourth quarter of 2000. A decision is expected in the first half of 2001.

Gas Rate Case—On July 17, 2000, PSCo filed a retail rate case with the CPUC requesting an annual increase in its jurisdictional gas department revenues of approximately $40 million. The request for a rate increase reflects revenues for additional plant investment, a 12.5-percent return on equity, new depreciation rates and recovery of the dismantlement costs associated with the Leyden Gas Storage facility. Hearings have not yet been scheduled.

SPS

Restructuring Legislation

Restructuring legislation has been enacted in Texas and New Mexico, as summarized below. SPS has made and continues to make filings with the Public Utility Commission of Texas (PUCT) and the New Mexico Public Regulation Commission (NMPRC), to address critical issues related to SPS's transition plans to retail competition. Retail competition is expected to be implemented in these states on or before Jan. 1, 2002.

Overview of New Mexico Legislation—In April 1999, New Mexico enacted the Electric Utility Restructuring Act of 1999, which provides for customer choice. The legislation provides for recovery of no less than 50 percent of stranded costs for all utilities as quantified by the NMPRC. Transition costs must be approved by the NMPRC prior to being recovered through a non-bypassable wires charge, which must be included in transition plan filings. SPS must separate its utility operations into at least two segments: energy generation and competitive services, and transmission and distribution utility services either by the creation of separate affiliates that may be owned by a common holding company or by the sale of assets to one or more third parties. A regulated company, in general, is prohibited from providing unregulated services. In May 2000, the NMPRC approved:

•: customer choice for residential, small commercial and educational customers by Jan. 1, 2002;
•: customer choice for commercial and industrial customers by July 1, 2002; and
•: completion of SPS corporate separation by Aug. 1, 2001.

Overview of Texas Legislation—In June 1999, an electric utility restructuring act (SB-7) was passed in Texas, which provides for the implementation of retail competition for most areas of the state beginning Jan. 1, 2002. The PUCT can delay the date for retail competition if a power region is unable to offer fair competition and reliable service during the 2001 pilot projects. The legislation requires:

•: a rate freeze for all customers until Jan. 1, 2002;
•: an annual earnings test through 2001;
•: a 6 percent rate reduction for those residential and small commercial customers who choose not to switch suppliers at the start of retail competition;
•: the unbundling of business activities, costs and rates relating to generation, transmission and distribution and retail services;

•: reductions in NOx and SO2 emissions; and
•: the recovery of stranded costs.

SB-7 requires each utility to unbundle its business activities into three separate legal entities: a power generation company, a regulated transmission and distribution company, and a retail electric provider. SB-7 limits the market share that a single generation provider can control to 20 percent of the generating capacity within a power region. The establishment of a qualified power region with multiple generation suppliers is required under SB-7 in order to implement full retail competition. SPS must return any excess earnings indicated in the annual earnings tests to customers during the period Jan. 1, 1999, through Dec. 31, 2001, or alternatively may direct any excess earnings to improvements in transmission and distribution facilities, to capital expenditures to improve air quality or to accelerate the amortization of regulatory assets, subject to PUCT approval.

Implementation—SPS filed its business separation plan in Texas during the first quarter of 2000 for the unbundling of power generation, transmission, and distribution and retail electric provider services. In April 2000, the PUCT approved SPS's business separation plan. Overall, the plan provides for the separation of all competitive energy services, the establishment of an Xcel Energy customer care company, which will provide customer services for all of Xcel Energy's operating utilities, and a formal code of conduct and compliance manual for managing affiliate transactions.

Subject to all required approvals and indebtedness restrictions, it is anticipated that all generation-related and certain other assets and liabilities will be transferred at net book value to newly-formed affiliates in accordance with SPS's business separation plan by Jan. 1, 2001 (approximately 50 percent of SPS's assets). It is expected that SPS and its affiliates will be capitalized consistent with their respective business operations.

In April 2000, SPS filed with the PUCT a stipulation agreement, which specifically addresses SPS implementation plans to meet the requirements of the Texas deregulation legislation. The stipulation provides for the implementation of full retail customer choice by SPS in its Texas service region, including the future divestiture of certain SPS generation assets. Subject to certain market conditions, SPS has agreed to divest 1,750 megawatts, at a minimum, by Jan. 1, 2002, and has specifically identified the plants that it would sell in connection with additional divestitures required to establish a qualified power region under SB-7. For SPS to comply with this qualified power region requirement and to implement full customer choice in Texas, a minimum of 2,843 megawatts and a maximum of 3,184 megawatts of existing power generation assets or capacity must be sold to third party non-affiliates. SPS has committed to complete these divestitures by Jan. 1, 2006. SPS expects some or all of these divestitures to be completed by the end of 2001. Management believes that these divestitures are in response to the legal requirements of SB-7 and that these divestitures can occur consistent with the pooling-of-interests accounting requirements. The stipulation provides that if the SEC determines that the divestitures would be a pooling violation, the divestitures would be delayed until at least September 2002 to meet the pooling-of-interests requirements.

In May 2000, the PUCT issued a rate order approving the stipulation. SPS has committed to transfer functional control of its electric transmission system to the Midwest Independent System Operator, Inc. (MISO), a regional transmission organization that will operate the transmission systems of multiple owners in the central United States.

SPS filed a rate case on March 31, 2000, to set the rates for the transmission and distribution services in Texas, which are to be unbundled and implemented on Jan. 1, 2002. SPS requested recovery

of all jurisdictional costs associated with restructuring in Texas. Hearings and a final rate order are not expected before 2001.

On June 1, 2000, SPS filed its transition plan with the NMPRC. SPS filed to establish rates for the transmission and distribution business in New Mexico, requesting approval of its corporate restructuring/separation and other associated matters. Hearings related to corporate separation are under way. A final rate order is not expected until mid 2001.

Financial Impact—With the issuance of a final written order by the PUCT in May 2000, addressing the implementation of electric utility restructuring, SPS discontinued regulatory accounting under SFAS 71 for the generation portion of its business during the second quarter of 2000. Consistent with current accounting rules, this resulted in extraordinary charges in the second and third quarters of 2000.

During the second quarter of 2000, SPS wrote off its generation-related regulatory assets and other deferred costs totaling approximately $19 million before taxes. This resulted in an after-tax extraordinary charge of approximately $13.7 million against the earnings of Xcel Energy and SPS. 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/defeasance of approximately $295 million of First Mortgage bonds.

SPS's transmission and distribution business continues to meet the requirements of SFAS 71, as that business is expected to remain regulated.

The total impacts of restructuring may be affected by the results of future state and federal regulatory proceedings prior to actual implementation of full competition, currently anticipated to begin on Jan. 1, 2002.

Additionally, there may be other significant financial implications of implementing SB-7 and electric restructuring in New Mexico. These implications include, but are not limited to investments in information technology, establishing an independent operation of the electric transmission systems, implementing the procedures to govern affiliate transactions, the pricing of unbundled energy services and the regulatory recovery of incurred costs related to these issues. Based on current estimates, these incurred costs could be as much as $75 million.

The resolution of these matters may have a significant financial impact on the financial position, results of operations and cash flows of SPS.

Earnings Test—Texas

On May 18, 2000, SPS filed its 1999 Earnings Report with the PUCT indicating no excess earnings. On Sept. 26, 2000, the PUCT staff and the Office of Public Utility Counsel (OPUC) filed a Notice of Disagreement with the PUCT indicating adjustments to SPS's calculations, which would result in excess earnings. During the third quarter of 2000, SPS recorded an estimated obligation for 1999 equal to $6.4 million and an estimated obligation for 2000 equal to $5.9 million. SPS continues to work with both the PUCT staff and the OPUC in resolving these matters and final resolution is pending.

Electric Cost Adjustment Mechanisms—Texas

The PUCT's regulations require periodic examination of SPS fuel and purchased power costs, the efficiency of the use of such fuel and purchased power, fuel acquisition and management policies and

purchase power commitments. SPS is required to file an application for the PUCT to retrospectively review, at least every three years, the operations of a utility's electricity generation and fuel management activities. In June 1998, SPS filed its reconciliation for the generation and fuel management activities totaling approximately $690 million, for the period from January 1995 through December 1997. In July 2000, the PUCT approved a settlement agreement between SPS and the general counsel of the PUCT, which provided for the recovery of substantially all fuel costs, including approximately $12.1 million of the Texas retail jurisdictional portion of the Thunder Basin judgment.

In June 2000, SPS filed an application for the PUCT to retrospectively review the operations of the utility's electricity generation and fuel management activities. In this application, SPS filed its reconciliation for the generation and fuel management activities totaling approximately $419 million, for the period from January 1998 through December 1999. Final approval is pending.

SPS filed an application on July 21, 2000, seeking to increase its fixed fuel factors as a result of recent increases in natural gas costs. On Aug. 10, 2000, SPS filed a second application seeking authority to surcharge approximately $26 million in fuel under recoveries and related interest accrued through the June 2000 billing cycle over the eight months ending May 2001. On Aug. 18, 2000, the PUCT consolidated these two filings into one docket. SPS reached a unanimous stipulation with all parties to the case resolving all outstanding issues. This stipulation was approved by the PUCT in September 2000 and allowed for the new fuel factors and surcharge factors to become effective in the October 2000 billing cycle.

New Mexico

The NMPRC regulations provide for a fuel and purchased power cost adjustment clause and a fixed annual fuel factor for SPS's New Mexico retail jurisdiction. SPS files monthly and annual reports of its fuel and purchased power costs with the NMPRC, which include the current over/under fuel collection calculation, plus interest. In addition, SPS revises its fixed fuel factor annually to recover projected fuel and purchased power costs as well as any over/under cost balance for the current year. SPS is required to petition for a change in the fixed fuel factor if the over/under recovery balance reaches $5 million.

SPS filed an unopposed motion with the NMPRC on Oct. 4, 2000, seeking to change the date for the implementation of its next fixed annual fuel factor. SPS was approximately $12.8 million under collected in fuel and purchased power costs through August 2000 and projected that these under collections would continue based on recent increases in natural gas costs. On Oct. 24, 2000, the NMPRC approved SPS's revised fixed annual fuel factor to be effective in the November 2000 billing cycle.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5. Commitments and Contingent Liabilities

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 6 and 14 to Xcel Energy's financial statements in Xcel Energy's Form 8-K dated Aug. 21, 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.

NSP-Minnesota

The circumstances set forth in Note 13 in NSP-Minnesota's Form 10, appropriately represent, in all material respects, the current status of commitments and contingent liabilities regarding public liability for claims resulting from any nuclear incident.

NSP-Wisconsin

Environmental Matters—As discussed in Note 8 to the Financial Statements in the 1999 NSP-Wisconsin Form 10-K, NSP-Wisconsin had been named as one of three potentially responsible parties in connection with environmental contamination at a site in Ashland, Wis. The United States Environmental Protection Agency (EPA) and Wisconsin Department of Natural Resources (WDNR) continue to evaluate proposed methods of remediating the contamination.

The Ashland site has been evaluated using the Hazardous Ranking System under the Comprehensive Environmental Response, Compensation and Liability Act. Preliminary results indicate that the Ashland site is likely to be named as a Superfund site. The governor of Wisconsin has concurred with this assessment, subject to the state of Wisconsin retaining the lead role in administering the cleanup of the site. Being named as a Superfund site will increase the administrative and transaction costs of the cleanup project.

The EPA and WDNR approved NSP-Wisconsin's proposal for an interim groundwater treatment system for the portion of the Ashland site that NSP-Wisconsin owns. The system began operation in September 2000 and is performing well. The cost to build the system was approximately $350,000.

In March 2000, NSP-Wisconsin received a formal data request related to its Wheaton generating facility from the EPA under Section 114(a) of the Clean Air Act. Data requests of this type from the EPA are sometimes used in anticipation of a potential enforcement action. The data request focuses on fuel usage, operating hours, operating loads and stack test data for the time period Jan. 1, 1999, to present. It was during this time period that two units at Wheaton had failed stack tests for particulate matter and carbon monoxide (unit 2) and particulate matter (unit 4) when firing oil at low load. The WDNR issued a Notice of Violation (NOV) letter to NSP-Wisconsin for each of these incidents. The two units were retested later in 1999 and found to be in compliance. The NOVs were formally closed out by the DNR in early January 2000.

On Oct. 26, 2000, EPA issued a letter in which it found that the NSP-Wisconsin French Island facility should be classifiied as a "large municipal waste combustor" under Section 129 of the Clean Air Act. This letter was contrary to a 1997 EPA letter in which the EPA had found that French Island should be classified as a "small combustor." If French Island is classified as a large municipal waste combustor, NSP-Wisconsin may be required to install additional control equipment or make operational changes to the facility. NSP-Wisconsin is determining its response to this letter.

PSCo

Environmental Matters—In 1996, a conservation organization filed a complaint in the U. S. District Court pursuant to provisions of the Federal Clean Air Act (the 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 Colorado Department of Public Health and Environment reached an agreement in principle resolving all air quality matters related to the facility. Resolution of this matter will require the installation of additional emission control equipment costing between $70 and $135 million, depending on the type of equipment ultimately installed. The equipment will be installed over a period of several years. In addition, the settlement may include civil penalties estimated to be less than $1 million.

Tax Matters—PSRI, a subsidiary of PSCo, owns and manages permanent life insurance policies on certain past and present employees. These corporate-owned life insurance (COLI) policies were entered into prior to June 20, 1986. Since 1986, Congress has passed various legislation to phase out the tax benefits associated with certain COLI policies, however, PSRI's policies have been grandfathered under this legislation. In August 1998, the IRS issued a Notice of Proposed Adjustment proposing to disallow the 1993 and 1994 deductions of interest expense related to policy loans on the COLI policies. In March 2000, the IRS amended its original adjustment to also disallow the interest deductions taken in tax years 1995 through 1997. The total disallowance of interest expense deductions for the five years as proposed by the IRS is approximately $175 million. A request for technical advice from the IRS national office with respect to the proposed adjustment is pending.

Management is vigorously contesting this issue. PSRI has not recorded any provision for income tax or interest expense related to this matter and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years. Management believes that PSRI's tax deduction of interest expense on life insurance policy loans was in full compliance with IRS regulations and believes that the resolution of this matter will not have a material adverse impact on PSCo's financial position, results of operations or cash flows.

6. Short-Term Borrowings and Financing Activities

NSP-Minnesota

At Sept. 30, 2000, NSP-Minnesota had approximately $576 million of short-term debt outstanding at a weighted average interest rate of 6.61 percent.

As of Sept. 30, 2000, NSP-Minnesota had a $300-million revolving credit facility under a commitment fee arrangement. This facility provides short-term financing in the form of bank loans, letters of credit and support for commercial paper sales.

NSP-Minnesota plans to file a $500 million long-term debt shelf registration during the fourth quarter of 2000.

NSP-Wisconsin

At Sept. 30, 2000, NSP-Wisconsin had approximately $77 million of short-term notes payable to NSP-Minnesota outstanding at a weighted average interest rate of 6.60 percent.

In October 2000, NSP-Wisconsin completed the sale of $80 million of 7.64 percent unsecured senior notes, maturing Oct. 1, 2008. The proceeds were used primarily to repay short-term debt.

In May 2000, 71,000 shares of NSP-Wisconsin common stock were issued for approximately $30 million to Xcel Energy. The proceeds were used to repay short-term debt.

PSCo

At Sept. 30, 2000, PSCo had approximately $310 million of short-term debt outstanding at a weighted average interest rate of 6.77 percent.

In July 2000, PSCo and its subsidiary PSCCC entered into a $600-million credit agreement, which will be used primarily to support the issuance of commercial paper by PSCo and PSCCC, but also provides for direct borrowings. This credit agreement, which is effective through July 19, 2001, replaced PSCo's existing $300 million 364-day facility, which expired on July 23, 2000, and PSCo and its subsidiaries' $300-million, multi-year facility, which would have terminated on Nov. 17, 2000.

SPS

At Sept. 30, 2000, SPS had approximately $655 million of short-term debt outstanding at a weighted average interest rate of 6.68 percent.

In July 2000, SPS entered into a $500-million credit agreement, which is effective through Jan. 20, 2002. The funds available from this credit agreement were used for used for general corporate purposes, including support for commercial paper, open market purchases, tender offer and defeasance costs of SPS's outstanding First Mortgage Bonds and other related restructuring costs. SPS is the initial borrower under this credit agreement; however, at the time of separation of the generation assets, the obligations under this credit agreement will be assumed by a newly formed generation company. See Note 4—Regulation and Rate Matters for more information on restructuring.

SPS entered into a credit agreement on Feb. 25, 2000. The commitment under the credit agreement is $300 million and is effective through Feb. 23, 2001. It will be used primarily for support for commercial paper, but also provides for direct borrowings.

During the first and second quarters of 2000, SPS repurchased in the open market approximately $27 million and $58 million, respectively, of its First Mortgage Bonds. During the third quarter of 2000, SPS completed a tender offer/defeasance of approximately $295 million of First Mortgage bonds, as discussed in Note 4.

7. Segment Information

Xcel Energy's Utility Subsidiaries each have 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 Texas, New Mexico, Kansas and Oklahoma. Revenues and net income are reported on the SPS Consolidated Income Statement. All figures are in thousands of dollars.

The Utility Subsidiaries of Xcel Energy segment results for the third quarter and the first nine months of 2000, reflect the write-off of special charges related to the merger.

NSP-Minnesota

Three months ended: Sept. 30, 2000		Electric Utility		Gas Utility			All Other		Eliminations/ Unallocated		Consolidated Total
Revenues from:
External customers		$	696,112	$	62,223		$	—	$	—	$	758,335
Internal customers			178		2,518			—		—		2,696

	Total revenue		696,290		64,741			—		—		761,031
Segment net income			31,686		(6,523	)		—		—		25,163
Sept. 30, 1999
Revenues from:
External customers		$	723,102	$	45,182		$	—	$	—	$	768,284
Internal customers			166		(1,206	)		—		—		(1,040	)

	Total revenue		723,268		43,976			—		—		767,244
Segment net income			87,030		(7,780	)		—		—		79,250

Nine months ended: Sept. 30, 2000		Electric Utility		Gas Utility			All Other		Eliminations/ Unallocated		Consolidated Total
Revenues from:
External customers		$	1,807,426	$	298,489		$	—	$	—	$	2,105,915
Internal customers			493		1,522			—		—		2,015

	Total revenue		1,807,919		300,011			—		—		2,107,930
Segment net income			75,611		6,660			—		—		82,271
Sept. 30, 1999
Revenues from:
External customers		$	1,775,938	$	244,058		$	—	$	—	$	2,019,996
Internal customers			506		(2,277	)		—		—		(1,771	)

	Total revenue		1,776,444		241,781			—		—		2,018,225
Segment net income			118,513		8,871			—		—		127,384

NSP-Wisconsin

Three months ended: Sept. 30, 2000		Electric Utility		Gas Utility			All Other		Eliminations/ Unallocated		Consolidated Total
Revenues from:
External customers		$	111,387	$	9,770		$	—	$	—	$	121,157
Internal customers			31		514			—		—		545

	Total revenue		111,418		10,284			—		—		121,702
Segment net income			3,887		(2,044	)		—		—		1,843
Sept. 30, 1999
Revenues from:
External customers		$	109,309	$	7,424		$	—	$	—	$	116,733
Internal customers			35		1,210			—		—		1,245

	Total revenue		109,344		8,634			—		—		117,978
Segment net income			8,025		(1,161	)		—		—		6,864

Nine months ended: Sept. 30, 2000		Electric Utility		Gas Utility		All Other		Eliminations/ Unallocated		Consolidated Total
Revenues from:
External customers		$	315,879	$	62,076	$	—	$	—	$	377,955
Internal customers			107		1,596		—		—		1,703

	Total revenue		315,986		63,672		—		—		379,658
Segment net income			17,741		897		—		—		18,639
Sept. 30, 1999
Revenues from:
External customers		$	309,052	$	52,495	$	—	$	—	$	361,547
Internal customers			97		2,377		—		—		2,474

	Total revenue		309,149		54,872		—		—		364,021
Segment net income			22,483		1,885		—		—		24,368

PSCo

Three months ended: Sept. 30, 2000		Electric Utility		Gas Utility			All Other		Eliminations/ Unallocated		Consolidated Total
Revenues from:
External customers		$	616,124	$	91,522		$	1,372	$	—	$	709,018
Internal customers			—		—			—		—		—

	Total revenue		616,124		91,522			1,372		—		709,018
Segment net income			7,633		(11,390	)		11,604		—		7,847
Sept. 30, 1999
Revenues from:
External customers		$	400,892	$	82,471		$	837	$	—	$	484,200
Internal customers			—		—			—		—		—

	Total revenue		400,832		82,471			837		—		484,200
Segment net income			49,092		(3,579	)		4,236		—		49,749

Nine months ended: Sept. 30, 2000		Electric Utility		Gas Utility		All Other		Eliminations/ Unallocated		Consolidated Total
Revenues from:
External customers		$	1,471,450	$	501,103	$	7,094	$	—	$	1,979,647
Internal customers			—		—		—		—		—

	Total revenue		1,471,450		501,103		7,094		—		1,979,647
Segment net income			100,418		13,468		23,640				137,526
Sept. 30, 1999
Revenues from:
External customers		$	1,155,904	$	477,537	$	5,794	$	—	$	1,639,235
Internal customers			—		—		—		—		—

	Total revenue		1,155,904		477,537		5,794		—		1,639,235
Segment net income			122,483		13,202		14,823		—		150,508

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 as of September 30, 2000, and the related consolidated statements of income for the three-month and nine-month periods ended September 30, 2000, and the consolidated statement of cash flows for the nine-month period ended September 30, 2000. These financial statements are the responsibility of the Company's management.

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, 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 financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States.

ARTHUR ANDERSEN LLP

Minneapolis, Minnesota,
November 10, 2000

TO NORTHERN STATES POWER COMPANY—WISCONSIN:

We have reviewed the accompanying consolidated balance sheet of Northern States Power Company—Wisconsin as of September 30, 2000, and the related consolidated statements of income for the three-month and nine-month periods ended September 30, 2000, and the consolidated statement of cash flows for the nine-month period ended September 30, 2000. These financial statements are the responsibility of the Company's management.

ARTHUR ANDERSEN LLP

Minneapolis, Minnesota,
November 10, 2000

TO PUBLIC SERVICE COMPANY OF COLORADO:

We have reviewed the accompanying consolidated balance sheet of Public Service Company of Colorado and subsidiaries as of September 30, 2000, and the related consolidated statements of income for the three-month and nine-month periods ended September 30, 2000 and 1999, and the consolidated statements of cash flows for the nine-month periods ended September 30, 2000 and 1999. These financial statements are the responsibility of the Company's management.

We have previously audited, in accordance with generally accepted auditing standards, the consolidated balance sheet of Public Service Company of Colorado and subsidiaries as of December 31, 1999, and the related consolidated statements of income, shareholder's equity and cash flows for the year then ended (not presented separately herein), and in our report dated February 15, 2000, we expressed an unqualified opinion on these financial statements. In our opinion, the information set forth in the accompanying consolidated condensed balance sheet as of December 31, 1999, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

ARTHUR ANDERSEN LLP

Minneapolis, Minnesota,
November 10, 2000

TO SOUTHWESTERN PUBLIC SERVICE COMPANY:

We have reviewed the accompanying balance sheet of Southwestern Public Service Company as of September 30, 2000, and the related statements of income for the three-month and nine-month periods ended September 30, 2000 and 1999, and the statements of cash flows for the nine-month periods ended September 30, 2000 and 1999. These financial statements are the responsibility of the Company's management.

We have previously audited, in accordance with generally accepted auditing standards, the balance sheet of Southwestern Public Service Company as of December 31, 1999, and the related statements of income, shareholder's equity and cash flows for the year then ended (not presented separately herein),

and in our report dated February 15, 2000, we expressed an unqualified opinion on these financial statements. In our opinion, the information set forth in the accompanying condensed balance sheet as of December 31, 1999, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

ARTHUR ANDERSEN LLP

Minneapolis, Minnesota,
November 10, 2000

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
•: business conditions in the energy industry
•: competitive factors
•: unusual weather
•: changes in federal or state legislation
•: regulation
•: the other risk factors listed from time to time by the Utility Subs of Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to this Report on Form 10-Q for the quarter ended Sept. 30, 2000.

NSP—MINNESOTA'S MANAGEMENT'S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

NSP—Minnesota's net income was approximately $82 million for the first nine months of 2000, compared with approximately $127 million for the first nine months of 1999.

Special Charges

During the third quarter of 2000, NSP-Minnesota expensed pretax special charges totaling approximately $59.1 million. The pretax charges included expenses related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE and pretax charges pertaining to incremental costs of transition and integration activities associated with the merger. For more information, see Note 2.

Electric Utility Margins

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 variable production expenses and, therefore, higher costs in periods of extreme temperatures can result in an adverse earnings impact.

	Nine Months Ended Sept. 30
(Millions of dollars)	2000			1999
Electric revenue	$	1,808		$	1,776
Electric fuel and purchased power		(637	)		(648	)

Electric margin	$	1,171		$	1,128

Electric revenue and margin for the first nine months of 2000 increased, compared with the first nine months of 1999, largely due to actual retail sales growth of 2.5 percent. Weather-adjusted retail sales growth increased electric margin by approximately $38 million, but was partially offset by unfavorable temperatures which decreased electric margin by approximately $11 million. In addition, NSP-Minnesota's wholesale operation increased electric margin by approximately $17 milllion.

Gas Utility Margins

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

	Nine Months Ended Sept. 30
(Millions of dollars)	2000			1999
Gas revenue	$	300		$	242
Cost of gas purchased and transported		(200	)		(148	)

Gas margin	$	100		$	94

Gas revenue for the first nine months of 2000 increased, compared with the first nine months of 1999, largely due to increased cost of gas, which is recovered in Minnesota through the purchased gas adjustment clause. Gas margin increased due to firm gas sales growth, increased interruptible sales and higher transportation revenues.

Non-Fuel Operating Expense and Other Costs

Regulated Other Operation and Maintenance Expense increased by approximately $16 million, or 3.0 percent, for the first nine months of 2000, compared with the first nine months of 1999. The increase is largely due to the timing of outages at the Prairie Island and Monticello nuclear plants, which increased costs by $17 million.

Depreciation and Amortization Expense increased by approximately $11 million, or 4.9 percent, for the nine months of 2000, compared with the first nine months of 1999, primarily due to increased capital additions to utility plant.

Interest expense increased by approximately $18 million, or 24.4 percent, for the first nine months of 2000, compared with the nine months of 1999, primarily due to increased debt levels.

NSP—WISCONSIN'S MANAGEMENT'S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

NSP—Wisconsin's net income was $18.6 million for the first nine months of 2000, compared with $24.4 million for the first nine months of 1999.

Special Charges

During the third quarter of 2000, NSP-Wisconsin expensed pretax special charges totaling approximately $10.8 million. The pretax charges included expenses related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE and pretax charges pertaining to incremental costs of transition and integration activities associated with the merger. For more information, see Note 2.

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. Wisconsin does not have an automatic retail electric fuel adjustment clause. Instead, it has a procedure which compares actual monthly and anticipated annual fuel costs with those costs that were included in the latest retail electric rates approved by the PSCW. If the comparison results in a difference outside a certain range, the PSCW may hold hearings limited to fuel costs and revise rates. Therefore, the fuel clause cost recovery in Wisconsin does not allow for complete recovery of all variable production expenses and higher costs, particularly in periods of extreme temperatures, can result in an adverse earnings impact.

	Nine Months Ended Sept. 30
(Millions of dollars)	2000			1999
Electric revenue	$	316		$	309
Electric fuel and purchased power		(160	)		(157	)

Electric margin	$	156		$	152

Electric revenue and margin for the first nine months of 2000 increased, compared with the first nine months of 1999, largely due to retail sales growth of 2 percent. This was partially offset by unfavorable temperatures, which reduced electric margin by approximately $1.3 million.

Gas Utility Margins

	Nine Months Ended Sept. 30
(Millions of dollars)	2000			1999
Gas revenue	$	64		$	55
Cost of gas purchased and transported		(45	)		(36	)

Gas margin	$	19		$	19

Gas revenue for the first nine months of 2000 increased, compared with the first nine months of 1999, due to higher cost of gas and sales growth. Gas margin was flat, largely due to unfavorable temperatures during 2000, which offset sales growth.

Non-Fuel Operating Expense and Other Costs

Regulated Other Operation and Maintenance Expense was stable, increasing by approximately $1.7 million, or 2.2 percent, for the first nine months of 2000, compared with the first nine months of 1999. The increase is largely due to expense timing and general inflation.

Interest expense increased by approximately $0.4 million, or 2.7 percent, for the first nine months of 2000, compared with the first nine months of 1999, primarily due to higher short-term interest rates.

PSCo'S MANAGEMENT'S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

PSCo's net income was $137.5 million for the first nine months of 2000, compared with $150.5 million for the first nine months of 1999.

Special Charges

During the third quarter of 2000, PSCo expensed pretax special charges totaling approximately $63.1 million. The pretax charges included expenses related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE and pretax charges pertaining to incremental costs of transition and integration activities associated with the merger. For more information, see Note 2. In addition, PSCo recognized a loss of $1.7 million attributed to the sale of Colorado Natural Fuels, LLC in August 2000.

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. PSCo has adjustment clauses that allow certain costs to be passed through to retail customers. The ICA allows for an equal sharing among customers and shareholders of certain fuel and energy cost increases and decreases. 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. Therefore, the fuel clause cost recovery does not allow for complete recovery of all variable production expenses and higher costs can result in an adverse earnings impact.

	Nine Months Ended Sept. 30
(Millions of dollars)	2000			1999
Electric revenue	$	1,471		$	1,156
Electric fuel and purchased power		(781	)		(508	)

Electric margin	$	690		$	648

Electric revenue and margin for the first nine months of 2000 increased, compared with the first nine months of 1999, largely due to retail sales growth of 3.3 percent and wholesale sales growth of 48.7 percent. PSCo's wholesale energy marketing and trading operation provided approximately $37 million of additional electric margin due to favorable market condition in the western United States. Increases in electric revenue and margin were partially offset by regulatory adjustments in

Colorado, which reduced revenue and margins by approximately $16 million. For more information see Note 4.

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.

	Nine Months Ended Sept. 30
(Millions of dollars)	2000			1999
Gas revenue	$	501		$	478
Cost of gas purchased and transported		(296	)		(295	)

Gas margin	$	205		$	183

Gas revenue and margin for the first nine months of 2000 increased, compared with the first nine months of 1999, largely due to higher base rates effective July 1, 1999, resulting from PSCo's 1998 gas rate case. In addition, gas transportation revenues increased, compared with the first nine months of 2000, primarily due to 17.3 percent higher deliveries and higher transportation rates effective July 1, 1999.

Non-Fuel Operating Expense and Other Costs

Regulated Other Operation and Maintenance Expense was fairly stable, increasing by approximately $0.9 million, or 0.3 percent, for the first nine months of 2000, compared with the first nine months of 1999.

Depreciation and Amortization Expense increased by approximately $4.5 million, or 3.0 percent, for the first nine months of 2000, compared with the first nine months of 1999, primarily due to increased capital additions to utility plant.

Interest expense increased by approximately $6.8 million, or 6.1 percent, for the first nine months of 2000, compared with the first nine months of 1999, primarily due to the issuance of the $200 million of 6⁷/8% Series A Notes in July 1999.

SPS'S MANAGEMENT'S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

SPS's net income was $59.8 million for the first nine months of 2000, compared with $88.8 million for the first nine months of 1999.

Extraordinary Items

During the second quarter of 2000, SPS wrote off its generation-related regulatory assets and other deferred costs for an extraordinary charge of approximately $19 million before taxes, or $13.7 million after tax. During the third quarter of 2000, SPS recorded an additional extraordinary charge of $8.2 million before tax, or $5.3 million after tax, related to the tender offer/defeasance of approximately $295 million of First Mortgage bonds. For more information on SPS restructuring, see Note 4.

Special Charges

During the third quarter of 2000, SPS expensed pretax special charges totaling approximately $19.9 million. The pretax charges included expenses related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE and pretax charges pertaining to incremental costs of transition and integration activities associated with the merger. For more information, see Note 2.

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's 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 result in an adverse earnings impact.

	Nine Months Ended Sept. 30
(Millions of dollars)	2000			1999
Electric revenue	$	792		$	717
Electric fuel and purchased power		(397	)		(345	)

Electric margin	$	395		$	372

Electric revenue and margin for the first nine months of 2000 increased, compared with the first nine months of 1999, largely due to sales growth and the effects of warmer and drier summer and early fall weather. The summer and early fall of 2000 was 15.5 percent warmer than the corresponding period in 1999, resulting in higher retail and wholesale sales. The impact of higher sales was reduced by $12.3 million, representing the estimated provision for potential overearnings in Texas for calendar 1999 and nine months of calendar 2000. For more information on the overestimated earnings, see Note 4.

Non-Fuel Operating Expense and Other Costs

Regulated Other Operation and Maintenance Expense increased by approximately $18.1 million, or 18.6 percent, for the first nine months of 2000, compared with the first nine months of 1999, primarily due to increases in steam generation expenses, transmission expenses and customer expenses.

Depreciation and Amortization Expense increased by approximately $2.7 million, or 4.9 percent, for the first nine months of 2000, compared with the first nine months of 1999, primarily due to increased capital additions to utility plant.

Interest expense increased by approximately $1.4 million, or 3.5 percent, for the first nine months of 2000, compared with the first nine months of 1999, primarily due to the increase in short-term debt associated with the tender offer/defeasance of SPS's First Mortgage bonds.

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-Wisconsin's, PSCo's and SPS's 1999 Form 10-K, to Item 8 of NSP-Minnesota's Form 10, and to Part II, Item 1 of NSP- Wisconsin's, PSCo's and SPS's Form 10-Q's for the quarters ended March 31, 2000 and June 30, 2000 for a description of certain legal proceedings presently pending. There are no new significant cases to report against Xcel Energy or its subsidiaries and there have been no notable changes in the previously reported proceedings, except as set forth below.

NSP—Minnesota

On Dec. 11, 1998, a gas explosion in St. Cloud, Minn., killed four people, including two NSP-Minnesota employees, injured approximately 14 people and damaged several buildings. The accident occurred as a crew from Cable Constructors Inc. (CCI) was installing fiber optic cable for Seren, a subsidiary of Xcel Energy. Seren, CCI and Sirti, an architecture/engineering firm retained by Seren, are named as defendants in 10 lawsuits relating to the explosion. NSP-Minnesota is a defendant in eight of the lawsuits. NSP-Minnesota and Seren deny any liability for this accident. On July 11, 2000, the National Transportation Safety Board issued a report, which determined that CCI's inadequate installation procedures and delay in reporting the gas hit were the proximate cause of the accident. NSP-Minnesota has a self-insured retention deductible of $2 million with general liability coverage limits of $185 million. Seren's primary insurance coverage is $1 million and its secondary insurance coverage is $185 million. The ultimate cost to NSP-Minnesota and Seren, if any, is presently unknown.

In April 1997, a fire damaged several buildings in downtown Grand Forks, N.D., during a flood in the city. On July 23, 1998, the St. Paul Mercury Insurance Co. commenced a lawsuit against NSP-Minnesota for damages in excess of $15 million. The suit was filed in the District Court in Grand Forks County in North Dakota. The insurance company alleges the fire was electrical in origin and that NSP-Minnesota was legally responsible for the fire because it failed to shut off electrical power to downtown Grand Forks during the flood and prior to the fire. Seven additional lawsuits were filed against NSP-Minnesota by insurance companies that insured businesses damaged by the fire. One additional lawsuit filed by the First National Bank of Grand Forks is venued in Federal Court. The total of damages being sought by all these lawsuits is in excess of $30 million. NSP-Minnesota denied any liability, asserting that it was not legally responsible for this unforeseeable event. Trial concerning the state court lawsuits commenced on Aug. 1, 2000, and concluded on Sept. 7, 2000. On Sept. 8, 2000, after deliberating for only one hour, a jury returned a defense verdict in favor of NSP-Minnesota. It is unknown whether the plaintiffs will appeal. NSP-Minnesota has a self-insured retention deductible of $2 million, with general liability insurance coverage limits of $150 million. The ultimate cost to Xcel Energy and NSP-Minnesota, if any, is unknown at this time.

NSP-Wisconsin

On Sept. 25, 2000, NSP-Wisconsin was served with a complaint 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 them to treble damages. The amount of their alleged damages is unknown.

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 PSCo.
15(b)		Letter from Arthur Andersen LLP regarding unaudited interim information for SPS.
27.01		Financial Data Schedule for NSP-Minnesota for the nine months ended Sept. 30, 2000.
27.02		Financial Data Schedule for NSP-Wisconsin for the nine months ended Sept. 30, 2000.
27.03		Financial Data Schedule for PSCo for the nine months ended Sept. 30, 2000.
27.04		Financial Data Schedule for SPS for the nine months ended Sept. 30, 2000.
99.01		Statement pursuant to Private Securities Litigation Reform Act of 1995.

(b) Reports on Form 8-K

The following reports on Form 8-K were filed either during the three months ended Sept. 30, 2000, or between Sept. 30, 2000, and the date of this report:

NSP-Wisconsin

Aug. 18, 2000 (filed Aug. 23, 2000)—Item 4 and 7. Change in Registrant's Certifying Accountants and Exhibits. Re: Disclosure of NSP-Wisconsin's removing PricewaterhouseCoopers LLP as its principal auditors.

Aug. 28, 2000 (filed Aug. 31, 2000)—Item 4. Change in Registrant's Certifying Accountants and Exhibits. Re: Disclosure of NSP-Wisconsin's appointed Arthur Andersen LLP as its principal auditors.

Sept. 28, 2000 (filed Sept. 28, 2000)—Item 5 and 7. Other and Exhibits. Re: Disclosure of NSP-Wisconsin's Underwriting Agreement and Prospectus Supplement relating to $80 million of 7.64 percent Senior Notes, Series due 2008.

SPS

July 24, 2000 (filed July 24, 2000)—Item 5 and 7. Other and Exhibits. Re: Disclosure of SPS's announcement of the commencement of a tender offer for its First Mortgage bonds.

NORTHERN STATES POWER COMPANY (A MINNESOTA CORPORATION) SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on Nov. 14, 2000.

		Northern States Power Company (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 COMPANY (A WISCONSIN CORPORATION) SIGNATURES

		Northern States Power Company (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 COMPANY OF COLORADO SIGNATURES

		Public Service Company 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 COMPANY

		Southwestern Public Service Company (Registrant)
		/s/ J. THOMAS PETILLO J. Thomas Petillo Vice President
		/s/ DAVID HUDSON David Hudson Secretary & Treasurer

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Northern States Power 10-Q2000 Q3 Quarterly report

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