NORTHERN STATES POWER CO - 10-Q Quarterly Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended Sept. 30, 2003


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

For the transition period from _______to________


	Exact name of registrant as specified in its charter, State or
	other jurisdiction of incorporation or organization, Address of
Commission	principal executive offices and Registrant’s Telephone Number,	IRS Employer
File Number	including area code	Identification No.

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

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

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

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

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

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.


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

TABLE OF CONTENTS


PART I - FINANCIAL INFORMATION
	Item 1. Financial Statements
	Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
	Item 4. CONTROLS AND PROCEDURES
Part II. OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 6. Exhibits and Reports on Form 8-K
EXHIBIT INDEX
EX-31.01 Certification-Section 302-NSP-Minnesota
EX-31.02 Certification-Section 302-NSP-Wisconsin
EX-31.03 Certification-Section 302-PSCo.
EX-31.04 Certification-Section 302-SPS
EX-32.01 Certification-Section 906-NSP-Minnesota
EX-32.02 Certification-Section 906-NSP-Wisconsin
EX-32.03 Certification-Section 906-PSCo.
EX-32.04 Certification-Section 906-SPS
EX-99.01 Statement-Securities Litigation Reform

Table of Contents

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Item 2. Management’s Discussion and Analysis

Item 4. Controls and Procedures

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

Item 6. Exhibits and Reports on Form 8-K

This combined Form 10-Q is separately filed by Northern States Power Co., a Minnesota corporation (NSP-Minnesota), Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin), Public Service Co. of Colorado (PSCo) and Southwestern Public Service Co. (SPS). NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are all wholly owned subsidiaries of Xcel Energy, Inc. (Xcel Energy). Xcel Energy is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Additional information on Xcel Energy is available in various filings with the SEC.

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

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

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

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


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

			2003			2002			2003			2002

Operating revenues:
	Electric utility		$	750,318		$	717,173		$	1,908,867		$	1,818,973
	Natural gas utility			58,366			31,186			480,494			308,504
	Electric trading margin			6,492			(3,059	)		9,893			(1,917	)
	Other			(789	)		6,836			10,149			18,800

		Total operating revenues		814,387			752,136			2,409,403			2,144,360
Operating expenses:
	Electric fuel and purchased power			268,420			236,033			682,154			613,386
	Cost of natural gas sold and transported			36,238			21,848			367,700			209,726
	Other operating and maintenance expenses			213,433			190,189			637,022			600,291
	Depreciation and amortization			94,174			89,285			284,845			262,274
	Taxes (other than income taxes)			46,897			45,363			134,073			131,291
	Special charges (see Note 2)			—			—			—			4,324

		Total operating expenses		659,162			582,718			2,105,794			1,821,292

Operating income				155,225			169,418			303,609			323,068
Other income (expense):
	Interest income			1,428			5,315			4,821			12,235
	Other nonoperating income			4,025			63			12,179			10,521
	Nonoperating expense			(1,898	)		(1,669	)		(5,067	)		(4,487	)

		Total other income (expense)		3,555			3,709			11,933			18,269
Interest charges and financing costs:
	Interest charges - net of amounts capitalized (including financing costs of $2,440, $1,104, $6,420 and $3,293, respectively)			31,028			30,805			92,923			65,423
	Distributions on redeemable preferred securities of subsidiary trusts			1,313			3,938			9,188			11,813

		Total interest charges and financing costs		32,341			34,743			102,111			77,236
Income before income taxes				126,439			138,384			213,431			264,101
Income taxes				46,029			55,392			68,929			105,652

Net income			$	80,410		$	82,992		$	144,502		$	158,449

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

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


				Nine Months Ended Sept. 30,

				2003			2002

Operating activities:
	Net income			$	144,502		$	158,449
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			293,633			270,556
		Nuclear fuel amortization			32,982			37,208
		Deferred income taxes			(4,615	)		(37,217	)
		Amortization of investment tax credits			(5,942	)		(6,236	)
		Allowance for equity funds used during construction			(9,464	)		(3,843	)
		Gain on sale of property			—			(6,785	)
		Change in accounts receivable			(16,817	)		35,017
		Change in inventories			(14,454	)		(6,345	)
		Change in other current assets			(18,981	)		50,586
		Change in accounts payable			(61,354	)		(54,831	)
		Change in other current liabilities			(89,715	)		34,986
		Change in other noncurrent assets			(50,569	)		(65,607	)
		Change in other noncurrent liabilities			46,152			57,439

			Net cash provided by operating activities		245,358			463,377
Investing activities:
	Capital/construction expenditures				(218,068	)		(280,584	)
	Allowance for equity funds used during construction				9,464			3,843
	Investments in external decommissioning fund				(42,669	)		(47,141	)
	Proceeds from sale of nonregulated property				—			11,152
	Decrease in restricted cash				23,000			—
	Other investments – net				(1,509	)		(1,599	)

			Net cash used in investing activities		(229,782	)		(314,329	)
Financing activities:
	Short-term borrowings - net				(69	)		(281,008	)
	Proceeds from issuance of long-term debt				372,459			624,690
	Repayment of long-term debt and preferred securities, including reacquisition premiums				(408,484	)		(778	)
	Capital contributions from parent				4,114			42,431
	Dividends paid to parent				(159,181	)		(143,728	)

			Net cash (used in) provided by financing activities		(191,161	)		241,607

Net (decrease) increase in cash and cash equivalents					(175,585	)		390,655
Cash and cash equivalents at beginning of period					310,338			17,169

Cash and cash equivalents at end of period				$	134,753		$	407,824

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

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


			Sept. 30, 2003			Dec. 31, 2002

ASSETS
Current assets:
	Cash and cash equivalents		$	134,753		$	310,338
	Restricted cash			—			23,000
	Accounts receivable - net of allowance for bad debts of $8,185 and $5,812, respectively			249,527			231,996
	Accounts receivable from affiliates			24,059			24,773
	Accrued unbilled revenues			101,825			109,435
	Materials and supplies inventories - at average cost			104,692			106,037
	Fuel inventory - at average cost			25,165			34,875
	Natural gas inventory - at average cost			49,894			24,385
	Prepayments and other			59,761			38,065

		Total current assets		749,676			902,904

Property, plant and equipment, at cost:
	Electric utility plant			7,202,471			6,855,807
	Natural gas utility plant			732,222			716,844
	Common and other plant			416,718			384,214
	Construction work in progress			329,876			313,931

		Total property, plant and equipment		8,681,287			8,270,796
	Less accumulated depreciation			(4,330,201	)		(4,624,988	)
	Nuclear fuel - net of accumulated amortization: $1,091,513 and $1,058,531, respectively			90,199			74,139

		Net property, plant and equipment		4,441,285			3,719,947

Other assets:
	Nuclear decommissioning fund			702,257			617,048
	Other investments			22,871			22,730
	Regulatory assets			417,139			212,539
	Prepaid pension asset			304,395			263,713
	Other			57,769			72,144

		Total other assets		1,504,431			1,188,174

		Total assets	$	6,695,392		$	5,811,025

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

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


			Sept. 30, 2003			Dec. 31, 2002

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	18,019		$	226,462
	Short-term debt			—			69
	Accounts payable			178,213			198,889
	Accounts payable to affiliates			26,188			66,866
	Taxes accrued			117,899			210,041
	Accrued interest			24,202			44,167
	Dividends payable to parent			53,468			52,280
	Other			74,132			43,255

		Total current liabilities		492,121			842,029

Deferred credits and other liabilities:
	Deferred income taxes			682,695			700,966
	Deferred investment tax credits			68,655			74,577
	Regulatory liabilities			567,454			486,035
	Benefit obligations and other			143,579			136,452
	Asset retirement obligations (see Note 1)			1,008,534			—

		Total deferred credits and other liabilities		2,470,917			1,398,030
Long-term debt				1,943,073			1,569,938
Mandatorily redeemable preferred securities of subsidiary trust				—			200,000
Common stockholder’s equity:
	Common stock - authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares			10			10
	Premium on common stock			817,983			813,869
	Retained earnings			971,292			987,158
	Accumulated other comprehensive income (loss)			(4	)		(9	)

		Total common stockholder’s equity		1,789,281			1,801,028

Commitments and contingencies (see Note 4)
		Total liabilities and equity	$	6,695,392		$	5,811,025

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

NSP-WISCONSIN AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(Thousands of Dollars)


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

				2003			2002			2003			2002

Operating revenues:
	Electric utility			$	129,207		$	121,578		$	357,781		$	348,689
	Natural gas utility				9,305			8,113			90,025			67,352
	Other				(34	)		541			103			652

			Total operating revenues		138,478			130,232			447,909			416,693
Operating expenses:
	Electric fuel and purchased power				62,945			54,971			175,127			159,617
	Cost of natural gas sold and transported				5,940			4,201			67,574			46,958
	Cost of sales: nonregulated and other				78			388			78			388
	Other operating and maintenance expenses				27,607			27,785			79,677			76,677
	Depreciation and amortization				11,766			11,313			34,903			33,152
	Taxes (other than income taxes)				4,119			4,012			12,378			12,229
	Special charges (see Note 2)				—			—			—			511

			Total operating expenses		112,455			102,670			369,737			329,532

Operating income					26,023			27,562			78,172			87,161
Other income (expense):
		Interest income			9			20			306			877
		Other nonoperating income			435			131			1,043			406
		Nonoperating expense			(123	)		(665	)		(329	)		(804	)

			Total other income (expense)		321			(514	)		1,020			479
Interest charges - net of amounts capitalized (including financing costs of $223, $224, $671 and $672, respectively)					5,661			5,763			17,085			17,336

Income before income taxes					20,683			21,285			62,107			70,304
Income taxes					8,404			8,789			25,127			27,439

Net income				$	12,279		$	12,496		$	36,980		$	42,865

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

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


				Nine Months Ended Sept. 30,

				2003			2002

Operating activities:
	Net income			$	36,980		$	42,865
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			35,685			34,052
		Deferred income taxes			5,481			2,364
		Amortization of investment tax credits			(594	)		(605	)
		Allowance for equity funds used during construction			(932	)		(406	)
		Undistributed equity in earnings of unconsolidated affiliates			92			(147	)
		Change in accounts receivable			15,621			299
		Change in inventories			(5,875	)		256
		Change in other current assets			7,415			13,274
		Change in accounts payable			(7,028	)		13,703
		Change in other current liabilities			3,221			12,897
		Change in other noncurrent assets			(5,743	)		(16,124	)
		Change in other noncurrent liabilities			(1,446	)		9,936

			Net cash provided by operating activities		82,877			112,364
Investing activities:
	Capital/construction expenditures				(40,261	)		(31,136	)
	Allowance for equity funds used during construction				932			406
	Other investments – net				37			(75	)

			Net cash used in investing activities		(39,292	)		(30,805	)
Financing activities:
	Short-term repayments - net				(6,880	)		(34,300	)
	Capital contributions from parent				692			2,438
	Dividends paid to parent				(37,397	)		(34,757	)

			Net cash used in financing activities		(43,585	)		(66,619	)

Net increase in cash and cash equivalents					—			14,940
Cash and cash equivalents at beginning of period					98			30

Cash and cash equivalents at end of period				$	98		$	14,970

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

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


			Sept. 30, 2003			Dec. 31, 2002

ASSETS
Current assets:
	Cash and cash equivalents		$	98		$	98
	Accounts receivable - net of allowance for bad debts of $1,434 and $1,373, respectively			33,632			47,890
	Accounts receivable from affiliates			96			1,460
	Accrued unbilled revenues			12,961			20,074
	Materials and supplies inventories - at average cost			6,219			5,994
	Fuel inventory - at average cost			4,361			6,006
	Natural gas inventory - at average cost			11,558			4,263
	Current deferred income taxes			5,644			—
	Prepaid taxes			10,133			13,735
	Prepayments and other			4,981			1,681

		Total current assets		89,683			101,201

Property, plant and equipment, at cost:
	Electric utility plant			1,182,556			1,161,901
	Natural gas utility plant			136,403			131,969
	Common and other plant			96,164			95,631
	Construction work in progress			32,094			18,305

		Total property, plant and equipment		1,447,217			1,407,806
	Less accumulated depreciation			(626,235	)		(592,187	)

		Net property, plant and equipment		820,982			815,619

Other assets:
	Other investments			9,690			9,817
	Regulatory assets			46,979			48,112
	Prepaid pension asset			44,427			38,557
	Other			7,862			7,577

		Total other assets		108,958			104,063

		Total assets	$	1,019,623		$	1,020,883

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

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


			Sept. 30, 2003			Dec. 31, 2002

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	40,034		$	40,034
	Short-term debt - notes payable to affiliate			—			6,880
	Accounts payable			17,520			23,535
	Accounts payable to affiliates			5,822			6,836
	Accrued interest			7,165			5,547
	Accrued payroll and benefits			5,723			4,398
	Dividends payable to parent			12,712			12,260
	Other			7,723			10,280

		Total current liabilities		96,699			109,770

Deferred credits and other liabilities:
	Deferred income taxes			159,658			146,471
	Deferred investment tax credits			14,225			14,820
	Regulatory liabilities			11,956			11,950
	Customer advances for construction			17,185			16,363
	Benefit obligations and other			29,296			29,663

		Total deferred credits and other liabilities		232,320			219,267

Long-term debt				273,173			273,108
Common stockholder’s equity:
	Common stock - authorized 1,000,000 shares of $100 par value; outstanding 933,000 shares			93,300			93,300
	Premium on common stock			63,673			62,981
	Retained earnings			261,589			262,459
	Other comprehensive loss			(1,131	)		(2	)

		Total common stockholder’s equity		417,431			418,738

Commitments and contingencies (see Note 4)
	Total liabilities and equity		$	1,019,623		$	1,020,883

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

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


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

				2003			2002			2003			2002

Operating revenues:
	Electric utility			$	587,429		$	497,885		$	1,574,652		$	1,387,414
	Natural gas utility				111,160			89,430			529,498			521,858
	Electric trading margin				645			2,276			657			(41	)
	Steam and other				4,354			4,535			15,723			17,513

			Total operating revenues		703,588			594,126			2,120,530			1,926,744
Operating expenses:
	Electric fuel and purchased power				325,370			232,021			856,087			637,963
	Cost of natural gas sold and transported				58,620			31,836			310,810			293,542
	Cost of sales - steam and other				2,519			3,782			8,946			7,581
	Other operating and maintenance expenses				118,069			111,801			348,809			334,580
	Depreciation and amortization				55,194			61,480			175,841			190,138
	Taxes (other than income taxes)				21,221			18,489			64,257			61,201
	Special charges (see Note 2)				—			1			—			132

			Total operating expenses		580,993			459,410			1,764,750			1,525,137

Operating income					122,595			134,716			355,780			401,607
Other income (expense):
		Interest income			473			664			2,484			1,034
		Other nonoperating income			2,839			1,266			8,722			5,396
		Nonoperating expense			(3,935	)		(4,358	)		(11,352	)		(8,970	)

			Total other income (expense)		(623	)		(2,428	)		(146	)		(2,540	)
Interest charges and financing costs:
		Interest charges - net of amounts capitalized (including financing costs of $2,025, $868, $5,940 and $2,606, respectively)			36,998			34,788			113,594			94,902
		Distributions on redeemable preferred securities of subsidiary trusts			—			3,686			7,372			11,058

			Total interest charges and financing costs		36,998			38,474			120,966			105,960
Income before income taxes					84,974			93,814			234,668			293,107
Income taxes					27,491			26,847			73,444			97,087

Net income				$	57,483		$	66,967		$	161,224		$	196,020

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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


				Nine Months Ended Sept. 30,

				2003			2002

Operating activities:
	Net income			$	161,224		$	196,020
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			181,674			196,764
		Deferred income taxes			86,147			26,572
		Amortization of investment tax credits			(5,499	)		(3,211	)
		Allowance for equity funds used during construction			(5,364	)		22
		Change in accounts receivable			(17,124	)		45,762
		Change in unbilled revenue			74,166			53,473
		Change in recoverable natural gas and electric costs			(52,055	)		(26,584	)
		Change in inventories			4,282			(21,090	)
		Change in other current assets			(65,092	)		5,121
		Change in accounts payable			(33,833	)		(60,217	)
		Change in other current liabilities			14,434			95,254
		Change in other noncurrent assets			35,786			(70,531	)
		Change in other noncurrent liabilities			30,213			5,820

			Net cash provided by operating activities		408,959			443,175
Investing activities:
	Capital/construction expenditures				(301,769	)		(359,412	)
	Allowance for equity funds used during construction				5,364			(22	)
	Proceeds from sale of property				4,636			17,527
	Other investments – net				(24,039	)		(1,036	)

			Net cash used in investing activities		(315,808	)		(342,943	)
Financing activities:
	Short-term repayments - net				(90,070	)		(487,388	)
	Repayment of long-term debt, including reacquisition premiums				(597,343	)		(3,142	)
	Proceeds from the issue of long term debt				816,221			594,000
	Capital contributions from parent				1,490			54,749
	Dividends paid to parent				(178,665	)		(169,985	)

			Net cash used in financing activities		(48,367	)		(11,766	)

Net increase in cash and cash equivalents					44,784			88,466
Cash and cash equivalents at beginning of period					25,924			22,666

Cash and cash equivalents at end of period				$	70,708		$	111,132

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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


			Sept. 30, 2003			Dec. 31, 2002

ASSETS
Current assets:
	Cash and cash equivalents		$	70,708		$	25,924
	Accounts receivable - net of allowance for bad debts of $11,355 and $13,685, respectively			198,789			165,743
	Accounts receivable from affiliates			3,485			19,407
	Accrued unbilled revenues			129,803			203,969
	Recoverable purchased natural gas and electric energy costs			117,412			23,131
	Materials and supplies inventories - at average cost			45,408			49,579
	Fuel inventory - at average cost			21,495			25,366
	Natural gas inventory - replacement cost in excess of LIFO: $87,701 and $20,502, respectively			89,438			85,679
	Derivative instruments valuation-at market			38,784			2,735
	Prepayments and other			42,714			13,257

		Total current assets		758,036			614,790

Property, plant and equipment, at cost:
	Electric utility plant			5,551,638			5,345,464
	Natural gas utility plant			1,537,056			1,494,017
	Steam, common and other plant			636,092			624,764
	Construction work in progress			469,221			456,800

		Total property, plant and equipment		8,194,007			7,921,045
	Less accumulated depreciation			(3,040,942	)		(2,896,978	)

		Net property, plant and equipment		5,153,065			5,024,067

Other assets:
	Other investments			21,892			12,319
	Regulatory assets			209,841			238,600
	Derivative instruments valuation-at market			694			1,494
	Deferred retail gas costs			22,272			1,130
	Other			29,969			32,526

		Total other assets		284,668			286,069

		Total assets	$	6,195,769		$	5,924,926

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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


			Sept. 30, 2003			Dec. 31, 2002

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	177,123		$	282,097
	Short-term debt			—			88,074
	Note payable to affiliate			13,146			15,142
	Accounts payable			280,669			318,005
	Accounts payable to affiliates			43,794			40,449
	Taxes accrued			53,209			47,363
	Accrued interest			45,782			44,391
	Dividends payable to parent			59,603			60,550
	Current portion of deferred income tax			52,412			22,298
	Derivative instruments valuation-at market			24,862			2,593
	Other			58,295			53,574

		Total current liabilities		808,895			974,536

Deferred credits and other liabilities:
	Deferred income taxes			612,077			553,006
	Deferred investment tax credits			71,963			74,987
	Regulatory liabilities			43,877			45,707
	Minimum pension liability			104,773			104,773
	Benefit obligations and other			81,008			74,335
	Customers advances for construction			181,199			142,992

		Total deferred credits and other liabilities		1,094,897			995,800

Long-term debt				2,311,789			1,782,128
Mandatorily redeemable preferred securities of subsidiary trust				—			194,000
Common stockholder’s equity:
	Common stock - authorized 100 shares of $0.01 par value; outstanding 100 shares			—			—
	Premium on common stock			1,653,774			1,652,284
	Retained earnings			414,502			430,997
	Accumulated other comprehensive loss			(88,088	)		(104,819	)

		Total common stockholder’s equity		1,980,188			1,978,462

Commitments and contingencies (see Note 4)
		Total liabilities and equity	$	6,195,769		$	5,924,926

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(Thousands of Dollars)


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

			2003			2002			2003			2002

Operating revenues			$	380,463		$	291,857		$	909,402		$	770,466
Operating expenses:
	Electric fuel and purchased power			232,087			158,324			542,691			414,699
	Other operating and maintenance expenses			41,411			34,774			122,441			112,867
	Depreciation and amortization			22,210			22,487			65,519			65,778
	Taxes (other than income taxes)			11,791			13,884			35,078			39,861
	Special charges (see Note 2)			—			—			—			5,114

		Total operating expenses		307,499			229,469			765,729			638,319

Operating income				72,964			62,388			143,673			132,147
Other income (expense):
	Interest income			361			875			1,284			1,666
	Other nonoperating income			1,483			1,239			3,178			2,601
	Nonoperating expense			(72	)		(39	)		(143	)		(93	)

		Total other income (expense)		1,772			2,075			4,319			4,174
Interest charges and financing costs:
	Interest charges - net of amounts capitalized (including financing costs of $1,772, $1,535, $5,201 and $4,604, respectively)			11,548			11,570			33,954			34,404
	Distributions on redeemable preferred securities of subsidiary trust			1,308			1,963			5,233			5,888

		Total interest charges and financing costs		12,856			13,533			39,187			40,292

Income before income taxes				61,880			50,930			108,805			96,029
Income taxes				23,756			19,189			41,693			36,111

Net income			$	38,124		$	31,741		$	67,112		$	59,918

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

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


				Nine Months Ended Sept. 30,

				2003			2002

Operating activities:
	Net income			$	67,112		$	59,918
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			71,986			72,129
		Deferred income taxes			669			14,743
		Amortization of investment tax credits			(188	)		(187	)
		Allowance for equity funds used during construction			(2,380	)		(882	)
		Change in recoverable electric energy costs			(43,864	)		—
		Change in accounts receivable			(5,862	)		(10,764	)
		Change in inventories			609			(4,978	)
		Change in other current assets			(19,449	)		28,969
		Change in accounts payable			11,131			4,527
		Change in other current liabilities			13,916			(31,482	)
		Change in other noncurrent assets			(15,015	)		(15,487	)
		Change in other noncurrent liabilities			6,104			549

			Net cash provided by operating activities		84,769			117,055
Investing activities:
	Capital/construction expenditures				(77,876	)		(34,139	)
	Allowance for equity funds used during construction				2,380			882
	Other investments – net				(1,232	)		(3,003	)

			Net cash used in investing activities		(76,728	)		(36,260	)
Financing activities:
	Short-term borrowings – net				17,000			—
	Capital contributions from parent				1,391			615
	Dividends paid to parent				(73,319	)		(68,912	)

			Net cash used in financing activities		(54,928	)		(68,297	)

Net (decrease) increase in cash and cash equivalents					(46,887	)		12,498
Cash and cash equivalents at beginning of period					60,700			65,499

Cash and cash equivalents at end of period				$	13,813		$	77,997

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

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


			Sept. 30, 2003			Dec. 31, 2002

ASSETS
Current assets:
	Cash and cash equivalents		$	13,813		$	60,700
	Accounts receivable - net of allowance for bad debts of $2,277 and $1,559, respectively			61,076			49,460
	Accounts receivable from affiliates			17,033			22,787
	Accrued unbilled revenues			69,551			52,999
	Recoverable electric energy costs			60,303			16,439
	Materials and supplies inventories - at average cost			15,972			17,231
	Fuel inventory - at average cost			1,971			1,322
	Prepayments and other			8,956			6,059

		Total current assets		248,675			226,997

Property, plant and equipment, at cost:
	Electric utility plant			3,110,405			3,076,970
	Construction work in progress			89,070			64,908

		Total property, plant and equipment		3,199,475			3,141,878
	Less accumulated depreciation			(1,383,224	)		(1,338,340	)

		Net property, plant and equipment		1,816,251			1,803,538

Other assets:
	Other investments			15,614			14,382
	Intangible assets			40,063			—
	Regulatory assets			101,529			105,404
	Prepaid pension asset			59,977			105,044
	Other			8,560			9,979

		Total other assets		225,743			234,809

		Total assets	$	2,290,669		$	2,265,344

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

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


				Sept. 30, 2003			Dec. 31, 2002

LIABILITIES AND EQUITY
Current liabilities:
	Short-term debt			$	17,000		$	—
	Accounts payable				84,097			73,536
	Accounts payable to affiliates				10,174			9,604
	Taxes accrued				38,832			24,107
	Accrued interest				12,452			7,630
	Dividends payable to parent				23,759			24,427
	Current portion of deferred income taxes				27,161			13,034
	Other				20,131			23,649

			Total current liabilities		233,606			175,987

Deferred credits and other liabilities:
	Deferred income taxes				369,598			399,800
	Deferred investment tax credits				4,029			4,217
	Regulatory liabilities				2,257			2,363
	Minimum pension liability (see Note 10)				20,839			—
	Benefit obligations and other				37,489			28,605

			Total deferred credits and other liabilities		434,212			434,985

Long-term debt					725,878			725,662
Mandatorily redeemable preferred securities of subsidiary trust (see Note 5)					100,000			100,000
Common stockholder’s equity:
		Common stock - authorized 200 shares of $1.00 par value; outstanding 100 shares			—			—
		Premium on common stock			412,720			411,329
		Retained earnings			416,437			421,976
		Accumulated other comprehensive income (loss)			(32,184	)		(4,595	)

			Total common stockholder’s equity		796,973			828,710

Commitments and contingencies (see Note 4)
			Total liabilities and equity	$	2,290,669		$	2,265,344

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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, 2003, and Dec. 31, 2002; the results of their operations for the three and nine months ended Sept. 30, 2003 and 2002; and their cash flows for the nine months ended Sept. 30, 2003 and 2002. Due to the seasonality of electric and natural gas sales of Xcel Energy’s Utility Subsidiaries, interim results are not necessarily an appropriate base from which to project annual results.

The accounting policies of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are set forth in Note 1 to their consolidated financial statements in their respective Annual Reports on Form 10-K for the year ended Dec. 31, 2002. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-Ks.

Certain items in the 2002 statement of operations, statement of cash flows and balance sheet have been reclassified to conform to the 2003 presentation. These reclassifications had no effect on Stockholder’s Equity or Net Income as previously reported.

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

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

NSP-Minnesota

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

A summary of the accounting for the initial adoption of SFAS No. 143 by NSP-Minnesota on Jan. 1, 2003 is as follows:


	Increase (decrease) in:
	Plant			Regulatory			Long-Term
(Thousands of Dollars)	Assets			Assets			Liabilities

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

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

A reconciliation of the beginning and ending aggregate carrying amount of NSP-Minnesota’s asset retirement obligations recorded under SFAS No. 143 is shown in the table below for the nine months ended Sept. 30, 2003.


		Beginning								Revisions		Ending
		Balance		Liabilities		Liabilities				To Prior		Balance
(Thousands of Dollars)		Jan. 1, 2003		Incurred		Settled		Accretion		Estimates		Sept. 30, 2003

Steam plant retirement		$	2,725	$	—	$	—	$	101	$	—	$	2,826
Nuclear plant decommissioning			859,643		—		—		42,380		103,685		1,005,708

	Total liability	$	862,368	$	—	$	—	$	42,481	$	103,685	$	1,008,534

The adoption of SFAS No. 143 resulted in the recording of a capitalized plant asset of $131 million for the discounted cost of asset retirement as of the date the liability was incurred. Accumulated depreciation on this additional capitalized cost through the date of adoption of SFAS No. 143 was $111 million. A regulatory asset of $842 million was recognized for the accumulated SFAS No. 143 costs recognized for accretion of the initial liability and depreciation of the additional capitalized cost through adoption date. This regulatory asset was partially offset by $662 million for the reversal of the decommissioning costs previously accrued in accumulated depreciation for these plants prior to the implementation of SFAS No. 143. The net regulatory asset of $180 million at Jan. 1, 2003 reflects the excess of costs that would have been recorded in expense under SFAS No. 143 over the amount of costs recorded consistent with ratemaking cost recovery for NSP-Minnesota. We expect this regulatory asset to reverse over time since the costs to be accrued under SFAS No. 143 are the same as the costs to be recovered through current NSP-Minnesota ratemaking. Consequently, no cumulative effect adjustment to earnings or shareholders’ equity has been recorded for the adoption of SFAS No. 143 in 2003 as all such effects have been deferred as a regulatory asset.

In August 2003, prior estimates for the nuclear plant decommissioning obligations were revised to incorporate the assumptions made in NSP-Minnesota’s updated 2002 nuclear decommissioning filing with the Minnesota Public Utilities Commission (MPUC). The revised estimates resulted in an increase of $104 million to both the regulatory asset and the long-term liability, discussed previously. The revised estimates reflected changes in cost estimates due to changes in the escalation factor, changes in the estimated start date for decommissioning and changes in assumptions for storage of spent nuclear fuel. The changes in assumptions for the estimated start date for decommissioning and changes in the assumptions for storage of spent nuclear fuel are a result of recent Minnesota legislation that authorized additional spent nuclear fuel storage, as discussed in Note 9 to the consolidated financial statements.

The pro-forma liability to reflect amounts as if SFAS No. 143 had been applied as of Dec. 31, 2002, was $862 million, the same as the Jan. 1, 2003 amounts discussed previously. The pro-forma liability to reflect adoption of SFAS No. 143 as of Jan. 1, 2002, the beginning of the earliest period presented, was $810 million.

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

The fair value of NSP-Minnesota assets legally restricted for purposes of settling the nuclear asset retirement obligations is $844 million as of Sept. 30, 2003, including external nuclear decommissioning investment funds and internally funded amounts.

NSP-Minnesota, NSP-Wisconsin, PSCo and SPS

The adoption of SFAS No. 143 in 2003 also affects accrued plant removal costs for other generation, transmission and distribution facilities for the Utility Subsidiaries. Although SFAS No. 143 does not recognize the future accrual of removal costs as a Generally Accepted Accounting Principles liability, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, the Utility Subsidiaries have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the estimated amounts of future removal costs, which are considered regulatory liabilities under SFAS No. 71 that are accrued in accumulated depreciation, are as follows at Jan. 1, 2003:


	(Millions of Dollars)
NSP-Minnesota	$	304
NSP-Wisconsin	$	70
PSCo.	$	329
SPS	$	97

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

Regulatory Recovery Adjustment (2002) - During the first quarter of 2002, SPS wrote off approximately $5 million of restructuring costs relating to costs incurred to comply with legislation requiring a transition to retail competition in Texas, which was subsequently amended to delay the required transition.

Utility Restaffing (2002) - During the fourth quarter of 2001, Xcel Energy recorded an estimated liability for expected staff consolidation costs for an estimated 500 employees in several utility operating and corporate support areas of Xcel Energy. In the first quarter of 2002, the identification of affected employees was completed and additional pretax special charges of $9 million were expensed for the final costs of the utility-related staff consolidations. Approximately $6 million of these restaffing costs were allocated to the Utility Subsidiaries. All 564 of accrued staff terminations occurred in 2002 and as of Sept. 30, 2003, all severance payments have been made.

3. Ratemaking and Regulatory Matters (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

NSP-Minnesota Service Quality Investigations – As previously reported, the MPUC directed the Office of the Attorney General and the Minnesota Department of Commerce (state agencies) to investigate the accuracy of NSP-Minnesota’s electric reliability records, which are summarized and reported to the MPUC on a monthly basis with an annual true-up. On Aug. 4, 2003, the state agencies jointly filed with the MPUC a report issued by Fraudwise, an investigation firm engaged by the state agencies to investigate the validity of allegations involving the integrity of NSP-Minnesota’s service quality reporting. The findings of the report indicated instances of inconsistency and misstatement in the record-keeping system, but noted that these instances of manipulation appear to have been limited to a small number of employees. NSP-Minnesota is continuing its internal review of these matters and has taken certain remedial and disciplinary actions to address the record-keeping deficiencies.

On Sept. 24, 2003, NSP-Minnesota and the state agencies announced that they had reached a settlement agreement that would be submitted to the MPUC for its approval. Among the provisions are:

• $1 million in refunds to Minnesota customers who have experienced the longest duration of outages, which have been accrued at Sept. 30, 2003;

• additional actions to improve system reliability in an effort to reduce outage frequency and duration. These actions will target the primary outage causes, including tree trimming and cable replacement. At least an additional $15 million, above amounts being currently recovered in rates, is to be spent in Minnesota on these outage prevention improvements by Jan. 1, 2005; and

• development of a revised service quality plan containing a standard for service outage documentation, new performance measures, new thresholds for current performance measures and a new structure for consequences that will result from failure to meet these performance measures.

NSP-Minnesota is currently negotiating the details of the revised service quality plan with the state agencies. The new service quality plan, or a report on the progress of the negotiations, is expected to be filed with the MPUC on Nov. 14, 2003.

In 2002, the South Dakota Public Utilities Commission (SDPUC) investigated Xcel Energy’s service quality. In particular, the investigation focused on NSP-Minnesota operations in the Sioux Falls area. NSP-Minnesota committed to a number of actions to improve reliability, which are being implemented, and to provide an updated 10-year capacity plan to the SDPUC by the end of 2003. NSP-Minnesota is working to complete the commitments made last December relating to service quality in the Sioux Falls area. NSP-Minnesota also is working with the SDPUC to provide information and to answer inquiries regarding service quality. No docket has been opened.

Midwest Independent Transmission System Operator, Inc. (MISO) Electric Market Initiative (NSP-Minnesota and NSP-Wisconsin) - On July 25, 2003, MISO filed proposed changes to its regional open access transmission tariff to implement a new Transmission and Energy Markets Tariff (TEMT) that would establish certain wholesale energy and transmission service rates based on locational marginal cost pricing (LMP) to be effective in 2004. NSP-Minnesota and NSP-Wisconsin presently receive transmission services from MISO for service to their retail loads and would be subject to the new tariff, if approved by the FERC. After numerous parties, including several states, filed protests to the proposal, MISO filed on Oct. 17, 2003, to withdraw the TEMT without prejudice to refiling. The FERC issued an order approving the withdrawal and provided guidance on MISO’s proposals on Oct. 29, 2003. MISO is now starting the stakeholder consultation process to prepare and submit a revised TEMT in 2004. Management believes any new tariff, if approved by the FERC, could have a material effect on wholesale power supply or transmission service costs to NSP-Minnesota and NSP-Wisconsin.

NSP-Wisconsin General Rate Case - On June 1, 2003, NSP-Wisconsin filed its required biennial rate application with the Public Service Commission of Wisconsin (PSCW) requesting no change in Wisconsin retail electric and natural gas base rates. NSP-Wisconsin requested the PSCW approve its application without hearing, pending completion of the Staff’s audit. An order is expected in late 2003 or early 2004.

FERC Investigation Against All Wholesale Electric Sellers/California Refund Proceedings (PSCo) On June 25, 2003, the FERC issued a series of orders addressing the California electricity markets. Two of these were show cause orders. In the first show cause order, the FERC found that 24 entities may have worked in concert through partnerships, alliances or other arrangements to engage in activities that constitute gaming and/or anomalous market behavior. The FERC initiated the proceedings against these 24 entities requiring that they show cause why their behavior did not constitute gaming and/or anomalous market behavior. PSCo was not named in this order. In a second show cause order, the FERC indicated that various California parties, including the California Independent System Operator (CAISO), have alleged that 43 entities individually engaged in one or more of seven specific types of practices that the FERC has identified as constituting gaming or anomalous market behavior within the meaning of the CAISO and California Power Exchange tariffs. PSCo was listed in an attachment to that show cause order as having been alleged to have engaged in one of the seven identified practices, namely circular scheduling. Subsequent to the show cause order, PSCo provided information to the FERC staff showing PSCo did not engage in circular scheduling. On Aug. 29, 2003, the FERC trial staff filed a motion to dismiss PSCo from the show cause proceeding. Various California parties have opposed the motion to dismiss. They have also requested rehearing of the FERC’s show cause orders contending that the FERC should have named PSCo in the show cause orders as an entity that had engaged in a load shift transaction and a partnership that constituted gaming. PSCo has answered both the request for rehearing and the California parties’ opposition to the FERC staff’s motion to dismiss.

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

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

• an interim adjustment clause (IAC) that recovers 100 percent of prudently incurred 2003 electric fuel and purchased energy expense above the expense recovered through electric base rates during 2003. This clause is projected to recover energy costs totaling approximately $216 million in 2003;

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

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

In June 2003, the CPUC issued its initial written order approving the settlement agreement. The new rates were effective July 1, 2003. The CPUC issued its final decision in the rate case on Aug. 8, 2003. PSCo expects to file the rate design portion of the case on or before Dec. 8, 2003.

PSCo Fuel Adjustment Clause Proceedings - Certain wholesale electric sales customers of PSCo filed complaints with the FERC in 2002 alleging PSCo had been improperly collecting certain fuel and purchased energy costs through the wholesale fuel cost adjustment clause included in their rates. The FERC consolidated these complaints and set them for hearing. The complainants filed initial testimony in late April 2003 claiming the improper inclusion of fuel and purchased energy costs in the range of $40 million to $50 million related to the periods 1996 through 2002. PSCo submitted answering testimony in June 2003. The complainants filed rebuttal testimony on Aug. 1, 2003, and current claims have been reduced, now estimated at approximately $30 million. In August 2003, PSCo reached agreements in principle with all of the complainants under which such claims, as well as issues those customers had raised in response to PSCo’s wholesale general rate case filing (discussed below), were compromised and settled. Under the settlement agreements in principle, PSCo will make cash payments or billing credits to certain of the complaining customers totaling approximately $1.5 million. The settlements also provide for revisions to the base demand and energy rates filed in the PSCo wholesale electric rate case. PSCo and the other parties are negotiating the detailed settlement provisions, which are subject to FERC approval.

PSCo had a retail incentive cost adjustment (ICA) cost recovery mechanism in place for periods prior to 2003. The CPUC conducted a proceeding to review and approve the incurred and recoverable 2001 costs under the ICA. On July 10, 2003, a stipulation and settlement agreement was filed with the CPUC, which resolved all issues. Under the stipulation and settlement agreement, the recoverable costs for 2001 and 2002 will be reduced by $1.6 million. Additional evaluation of the 2002 recoverable ICA costs will be conducted in a future proceeding. The resulting impact on the reset of the allowed cost recovery and cost sharing under the ICA for

2002 was not significant. In addition, the stipulation and settlement agreement provides for a prospective rate design adjustment related to the maximum allowable natural gas hedging costs that will be a part of the electric commodity adjustment for 2004 and is expected to reduce 2004 rates by an estimated $4.6 million. The stipulation and settlement agreement was approved by the CPUC in September 2003.

At Sept. 30, 2003, PSCo has recorded its deferred fuel and purchased energy costs based on the expected rate recovery of its costs as filed in the above rate proceedings, without the adjustments proposed by various parties. Pending the outcome of these regulatory proceedings, we cannot at this time determine whether any customer refunds or disallowances of PSCo’s deferred costs will be required other than as discussed above.

PSCo Wholesale General Rate Case – On June 19, 2003, PSCo filed a wholesale electric rate case with the FERC, proposing to increase the annual electric sales rates charged to wholesale customers, other than Cheyenne Light Fuel & Power Co., a wholly owned subsidiary of Xcel Energy. On Aug. 1, 2003, PSCo submitted a revised filing correcting an error in the calculation of income tax costs. The revised filing requests an approximately $2-million annual increase with new rates effective in January 2004, subject to refund. As discussed above, in August 2003, PSCo reached a settlement in principle in this case and the separate wholesale fuel clause cases.

PSCo Electric Department Earnings Test Proceedings - PSCo has filed with the CPUC its annual electric department earnings test reports for 2001 and 2002. In both years, PSCo did not earn above its allowed authorized return on equity and, accordingly, has not recorded any refund obligations. In the 2001 proceeding, the Office of Consumer Counsel has proposed that the $10.9-million gain on the sale of the Boulder Hydroelectric Project be excluded from 2001 earnings and that possible refund of the gain be addressed in a separate proceeding. On Oct. 31, 2003, the administrative law judge ruled the gain was appropriately included in the 2001 earnings, and it is reasonable to amortize the gain over four years. In the 2002 proceeding, the CPUC has opened a docket to consider whether PSCo’s cost of debt has been adversely affected by the financial difficulties at NRG Energy, Inc., a nonregulated wholly owned subsidiary of Xcel Energy, and, if so, whether any adjustments to PSCo’s cost of capital should be made. The 2002 proceeding has been set for hearing in August 2004.

PSCo Gas Cost Prudence Review – As previously reported, in May 2002, the staff of the CPUC filed testimony in PSCo’s gas cost prudence review case, recommending $6.1 million in disallowances of gas costs for the July 2000 through June 2001 gas purchase year. On Feb. 10, 2003, an administrative law judge issued a recommended decision rejecting the proposed disallowances and approving PSCo’s gas costs for the subject gas purchase year as prudently incurred. The CPUC upheld the finding that PSCo was prudent and reasonable in its handling of the Western Natural Gas default in January 2001.

PSCo Annual Gas Cost Adjustment Filing – PSCo recovers the cost of natural gas that it purchases for its customers’ use through a gas cost adjustment mechanism in its gas rates filed with the CPUC. On Sept. 16, 2003, PSCo requested an $88.8-million increase in prices for its customers through its annual gas cost adjustment filing to reflect higher current and forecasted costs of natural gas. The price increase was approved by the CPUC and went into effect on Oct. 1, 2003.

PSCo Electric Capacity Cost Adjustment – In October 2003, PSCo filed with the CPUC an application to recover approximately $31.5 million of incremental electric capacity costs through a purchased capacity cost adjustment (PCCA) rider beginning March 1, 2004. The purpose of the PCCA is to recover purchased capacity payments to third party power suppliers that will not be recovered in PSCo’s current base electric rates or other recovery mechanism. In addition, PSCo has proposed to return to its retail customers 100 percent of any electric earnings in excess of its authorized rate of return on equity allowed in the last rate case, currently 10.75 percent. A decision by the CPUC is expected in 2004.

Home Builders Association of Metropolitan Denver (PSCo) – In February 2001, Home Builders Association of Metropolitan Denver (HBA) filed a complaint with the CPUC seeking a reparations award of $13.6 million for PSCo’s failure to update its gas extension policy construction allowances from 1996 to 2002 under its tariff. On Aug. 27, 2003, the CPUC issued a ruling with respect to this matter and on Sept. 24, 2003, adopted a written order in this proceeding. According to the CPUC decision, PSCo is to pay reparations to HBA members, including interest, based on a revised construction allowance for the period Feb. 24, 1999, through May 31, 2002. The level of reparations based on the revised construction allowance is not known at this time. However, management expects total reparations are likely to be less than $1.5 million. PSCo and HBA have both requested rehearing of the Aug. 27, 2003 CPUC order.

SPS Texas Fuel Reconciliation, Fuel Factor and Fuel Surcharge Applications - In June 2002, SPS filed an application for the Public Utility Commission of Texas (PUCT) to retrospectively review the operations of the utility’s electric generation and fuel management activities. In this application, SPS filed its reconciliation for electric generation and fuel management activities, totaling

approximately $608 million, from January 2000 through December 2001. In May 2003, a stipulation was approved by the PUCT. The stipulation resolves all issues regarding SPS’ fuel costs and wholesale trading activities through December 2001. SPS will withdraw, without prejudice, its request to share in 10 percent of margins from certain wholesale non-firm sales. SPS will recover $1.1 million from Texas customers for the proposed sharing of wholesale non-firm sales margins. The parties agreed that SPS would reduce its December 2001 fuel under-recovery balances by $5.8 million. Including the withdrawal of proposed margin sharing of wholesale non-firm sales, the net impact to SPS’ deferred fuel expense, before tax, is a reduction of $4.7 million.

In May 2003, SPS proposed to increase its voltage-level fuel factors to reflect increased fuel costs since the time SPS’ current fuel factors were approved in March 2002. The proposed fuel factors are expected to increase Texas annual retail revenues by approximately $60.2 million. SPS also reported to the PUCT that it has undercollected its fuel costs under the current Texas retail fixed fuel factors. In the same May 2003 application, SPS proposed to surcharge $13.2 million and related interest for fuel cost underrecoveries incurred through March 2003. In June 2003, the administrative law judge approved the increased fuel factors on an interim basis subject to hearings and completion of the case. The increased fuel factors became effective in July 2003. In July 2003, a unanimous settlement was reached adopting the surcharge and providing for the implementation of an expedited procedure for revising the fixed fuel factors on a semiannual basis. The surcharge will be collected from customers over an eight-month period. In August 2003, the PUCT approved the settlement and the new proposed fuel cost recovery process and the surcharge became effective in September 2003. The Texas retail fuel factors will change each November and May based on the projected cost of natural gas. Revenues will continue to be reconciled to fuel costs in accordance with Texas law.

In July 2003, SPS filed a second fuel cost surcharge factor application in Texas to recover an additional $26 million of fuel cost underrecoveries accrued during April through June 2003. In August 2003, the parties to the case filed a stipulation resolving various issues. The stipulation provided approval of SPS’ modified request to surcharge $15.7 million for the months April 2003 and May 2003 over 12 months beginning with the November 2003 billing cycle. The stipulation was approved by the PUCT in October 2003.

In November 2003, SPS submitted a third fuel cost surcharge factor application in Texas to recover an additional $25 million of fuel cost underrecoveries accrued during June through September 2003. If approved, the proposed surcharge will go into effect after the first surcharge is completed and will continue for 12 months beginning in May 2004. This case is pending review and approval by the PUCT.

SPS New Mexico Fuel Reconciliation and Fuel Factor Applications - On May 27, 2003, a hearing examiner for the New Mexico Public Regulatory Commission (NMPRC) issued a recommended decision on SPS’s fuel proceeding approving SPS utilizing a monthly fuel factor. SPS had been utilizing an annual fuel factor, which had allowed significant undercollections. The decision denied the intervernors’ request that all margins from off-system sales be credited to ratepayers. On Aug. 19, 2003, the NMPRC approved the hearing examiner’s recommended decision. In accordance with NMPRC regulations, SPS must file its next New Mexico fuel factor continuation case no later than August 2005.

SPS New Mexico Billing Practice Investigation – On Sept. 25, 2003, the NMPRC entered an order opening an investigation into estimated billing practices used to send estimated bills to approximately 9,500 customers for between two and five months. As part of the Sept. 25, 2003, order, the NMPRC also implemented temporary billing measures for customers whose bills were estimated. The temporary billing measures: (i) require SPS to apply the lowest fuel and purchased power cost adjustment factor that was applicable during the period when meters were being estimated, (ii) allow customers six months to pay bills in full without additional charges or disconnection, (iii) prohibit disconnection of service until Nov. 1, 2003, for any customer that received an estimated bill, (iv) require a written explanation of the fuel calculation used under the order and (v) order a report of the amount of fuel and purchased power costs foregone as a result of the interim relief, which amount will not be allowed to be recovered from customers. The proceeding has been referred to a hearing examiner.

TRANSLink Transmission Co., LLC (TRANSLink) – In 2002, NSP-Minnesota filed for MPUC approval to transfer functional control of its transmission system to TRANSLink, a proposed independent transmission company. In June 2003, the MPUC held a hearing on the TRANSLink application. At the hearing, the MPUC deferred any decision and indicated NSP-Minnesota could submit a supplemental or revised application to explain certain recent changes to the proposal and to respond to a number of issues and questions posed by the MPUC advisory staff and other parties. On Nov. 3, 2003, NSP-Minnesota submitted a status report to the MPUC indicating the participants are evaluating the TRANSLink proposal in light of recent events and would provide a further report within 30 days. Similar filings in North Dakota and Wisconsin are not contested, but have not been approved.

In 2002, SPS filed for PUCT and NMPRC approval to transfer functional control of its electric transmission system to TRANSLink, of which SPS would be a participant. In March 2003, the Southwest Power Pool (SPP) and the MISO cancelled their planned merger

to form a large mid-continent regional transmission organization (RTO). This development materially impacted SPS’ applications in Texas and New Mexico. SPS requested the cases be dismissed without prejudice while it evaluates possible RTO arrangements for the SPS system.

Xcel Energy is considering these developments, as well as the proceedings in process in other jurisdictions, to evaluate the future role of TRANSLink in providing transmission operations services for the Xcel Energy system. As of Sept. 30, 2003, Xcel Energy’s subsidiaries had deferred approximately $5 million of TRANSLink-related costs based on anticipated recovery in future rates.

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

Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on the Utility Subsidiaries’ financial position and results of operations.

NSP-Minnesota Notice of Violation - On Dec. 10, 2001, the Minnesota Pollution Control Agency (MPCA) issued a notice of violation to NSP-Minnesota alleging air quality violations related to the replacement of a coal conveyor and violations of an opacity limitation at the A.S. King generating plant. The MPCA based its notice of violation in part on an environmental protection agency (EPA) determination that the replacement constituted reconstruction of an affected facility under the Clean Air Act’s New Source Review requirements. On June 27, 2003, the EPA rejected NSP-Minnesota’s request for reconsideration of that determination. The New Source Performance Standard for coal handling systems is unlikely to require the installation of any emission controls not currently in place on the plant. It may impose additional monitoring requirements that would not have material impact on NSP-Minnesota or its operations. In addition, the MPCA or EPA may impose civil penalties for violations of up to $27,500 per day per violation. NSP-Minnesota is working with the MPCA to resolve the notice of violation.

French Island (NSP-Wisconsin) - On Oct. 20, 2003, the U.S. District Court in Madison, Wisconsin entered a consent decree settling the EPA’s claims against NSP-Wisconsin related to the French Island generating plant, but denying any liability. The consent decree is now enforceable. On or before Nov. 19, 2003, NSP-Wisconsin will pay a civil penalty of $500,000. At Sept. 30, 2003, NSP-Wisconsin has accrued all costs related to this matter.

Fort Collins Manufactured Gas Plant Site - Prior to 1926, Poudre Valley Gas Company, a predecessor of PSCo, operated a manufactured gas plant in Fort Collins, Colorado near the Cache la Poudre River. In 1926, after acquiring the Poudre Valley Gas Company, PSCo shut down the gas site and, years later, sold most of the property. In the mid-1990s, contamination associated with coal tar left behind by the gas plant operations was discovered on the gas plant site, and PSCo paid for a portion of a partial cleanup. Recently, an oily substance similar to coal tar has been discovered in the Cache la Poudre River. The source of this substance has not yet been identified. PSCo is working with government agencies, the current site owner and the City of Fort Collins (owner of a former landfill property between the River and the plant site) to address the substance found in the river as well as other environmental issues found on the property. PSCo estimates that the cost of initial removal and investigation activities will be approximately $250,000. Sufficient information is not available at this time to estimate the ultimate liability, if any, for this site.

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

St Cloud Gas Explosion (NSP-Minnesota) - As discussed previously in the Form 10-K for the period ending Dec. 31, 2002, 25 lawsuits have been filed as a result of a Dec. 11, 1998, gas explosion in St. Cloud, Minn. that killed four persons (including two employees of NSP-Minnesota), injured several others and damaged numerous buildings. Most of the lawsuits name as defendants NSP-Minnesota, Xcel Energy’s subsidiary Seren, Cable Constructors, Inc. (CCI) (the contractor that struck the marked gas line) and Sirti, an architectural/engineering firm hired by Seren for its St. Cloud cable installation project. The court granted the plaintiffs’ request to amend the complaint to seek punitive damages against Seren and CCI. The plaintiffs brought a similar motion against NSP-Minnesota. On Oct. 23, 2003, the court denied plaintiffs’ motion. On Nov. 11, 2003 court-ordered mediation was conducted. As a result of this mediation NSP-Minnesota reached a confidential settlement with a group of plaintiffs representing the most significant claims asserted against NSP-Minnesota. The settlements will be paid by NSP-Minnesota’s insurance carrier. A trial date has not been set for the remaining lawsuits.

Commodity Futures Trading Commission Investigation (PSCo) - On June 17, 2002, the Commodity Futures Trading Commission (CFTC) issued broad subpoenas to Xcel Energy on behalf of its affiliates, including PSCo, calling for production, among other things, of “all documents related to natural gas and electricity trading” (June 2002 subpoenas). Since that time, Xcel Energy has produced documents and other materials in response to numerous, more specific requests under the June 2002 subpoenas. Certain of these requests and Xcel Energy’s responses have concerned so-called “round-trip trades.” By a subpoena dated Jan. 29, 2003 and related letter requests (January 2003 subpoena), the CFTC has requested that Xcel Energy produce all documents related to all data submittals and documents provided to energy industry publications. Xcel Energy has produced documents and other materials in response to the January 2003 subpoena. Xcel Energy is cooperating in the CFTC investigation, but cannot predict the outcome of any investigation.

Golden Spread Electric Cooperative, Inc. (SPS) - In October 2001, Golden Spread Electric Cooperative, Inc. (Golden Spread) filed a complaint and request for investigation against SPS at the FERC. Golden Spread alleged SPS has violated provisions of a commitment and dispatch service agreement pursuant to which SPS conducts joint dispatch of SPS and Golden Spread electric generating resources. SPS filed a complaint against Golden Spread in which it has alleged that Golden Spread has failed to adhere to certain requirements of the commitment and dispatch service agreement. In May 2003, SPS and Golden Spread reached a settlement that was approved by the FERC in July 2003. The $5-million accrued costs for payments under the settlement have been deferred by SPS as they are for economic purchased energy and are recoverable from SPS customers through the respective jurisdictional fuel and purchased power cost recovery mechanisms.

Colorado Wildfires (PSCo) - In late October 2003, there were two wildfires in Colorado, one in Boulder County and the other in Douglas County. There was no loss of life, but there was property damage associated with these fires. Parties have asserted that one or both fires may have been caused by trees falling into Xcel Energy distribution lines. We are in the very preliminary stages of investigation as to the cause of each fire. It is reasonable likely that there will be future litigation relating to these fires and such litigation could be material.

Other - The circumstances set forth in Notes 13 and 14 to the consolidated financial statements in NSP-Minnesota’s, NSP-Wisconsin’s, PSCo’s and SPS’ Annual Reports on Form 10-K for the year ended Dec. 31, 2002, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference. Following is an unresolved contingency, which is material to the financial position of Xcel Energy’s Utility Subsidiaries:

• Tax Matters - Internal Revenue Service issue of Notice of Proposed Adjustment regarding the tax deductibility of corporate owned life insurance loan interest deductions taken by PSCo in tax years beginning in 1993.

5. Short-Term Borrowings, Long-term Debt and Financing Instruments (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

NSP-Minnesota

Financing Activity - On Oct. 1, 2003, NSP-Minnesota redeemed a total of $13.7 million of pollution control bonds consisting of $5.45 million related to the Minneapolis Community Development Agency, $3.4 million related to the City of Mankato and $4.85 million related to the City of Red Wing.

Dividend Restrictions - NSP-Minnesota has dividend restrictions imposed by state regulatory commissions, debt agreements and the SEC under the PUHCA limiting the amount of dividends NSP-Minnesota can pay to Xcel Energy. These restrictions include, but may not be limited to, the following:

• maintenance of an equity ratio of 43.74 percent to 53.46 percent;

• payment of dividends only from retained earnings; and

• debt covenant restrictions under the credit agreement for debt and interest coverage ratios.

NSP-Wisconsin

Financing Activity – On Oct. 2, 2003, NSP-Wisconsin issued $150 million of 5.25-percent first mortgage bonds due Oct. 1, 2018, in a private placement to qualified institutional buyers. The proceeds were used to repay short-term borrowings incurred to pay at maturity $40 million of 5.75 percent first mortgage bonds due Oct. 1, 2003, and to redeem $110 million of 7.25 percent first mortgage bonds. On Oct. 15, 2003, NSP-Wisconsin redeemed the $110 million of 7.25-percent first mortgage bonds, due March 1, 2023.

Dividend Restrictions - NSP-Wisconsin has dividend restrictions imposed by state regulatory commissions, debt agreements and the SEC under the PUHCA limiting the amount of dividends NSP-Wisconsin can pay to Xcel Energy. These restrictions include, but may not be limited to:

• maintenance of an equity ratio of 52 percent to 57 percent; and

• payment of dividends only from retained earnings.

PSCo

Dividend Restrictions - PSCo has dividend restrictions imposed by state regulatory commissions, debt agreements and the SEC under the PUHCA limiting the amount of dividends PSCo can pay to Xcel Energy. These restrictions include, but may not be limited to, the following:

• maintenance of a minimum equity ratio of 30 percent;

• payment of dividends only from retained earnings; and

• debt covenant restrictions under the credit agreement for debt and interest coverage ratios.

SPS

Financing Activity – On Oct. 6, 2003, SPS issued $100 million of 6-percent, Series C Senior Notes due 2033 in a private placement to qualified institutional buyers. On Oct. 15, 2003, the proceeds were used to redeem $100 million, 7.85-percent Trust Originated Preferred Securities of its trust subsidiary, Southwestern Public Service Capital I.

Dividend Restrictions - SPS has dividend restrictions imposed by state regulatory commissions, debt agreements and the SEC under the PUHCA limiting the amount of dividends SPS can pay to Xcel Energy. These restrictions include, but may not be limited to, the following:

SFAS No. 150 - In May 2003, the FASB issued SFAS No. 150 - “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (SFAS No. 150). SFAS No. 150 establishes standards for classifying and measuring as liabilities certain financial instruments that embody obligations of the issuer and have characteristics of both liabilities and equity, including:

• instruments that represent, or are indexed to, an obligation to buy back the issuer’s shares, regardless of whether the instrument is settled on a net-cash or gross physical basis;

• mandatorily redeemable equity instruments;

• written options that give the counterparty the right to require the issuer to buy back shares; and

• forward contracts that require the issuer to purchase shares.

In November 2003, the FASB posted a staff position, which delayed the implementation of SFAS 150, indefinitely. SPS had a special purpose subsidiary trust with outstanding mandatorily redeemable preferred securities of $100 million consolidated in SPS’ Consolidated Balance Sheets. This security was redeemed on Oct. 15, 2003. PSCo and NSP-Minnesota redeemed Trust Originated Preferred Securities on June 30, 2003, and July 31, 2003, respectively, and SFAS No. 150 will not affect such securities.

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

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

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


	Nine Months Ended Sept. 30, 2003

	NSP-			NSP-
(Millions of Dollars)	Minnesota			Wisconsin			PSCo			SPS

Accumulated other comprehensive income (loss) related to cash flow hedges – Jan. 1, 2003	$	0.0		$	0.0		$	1.0		$	(4.6	)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		(4.0	)		(1.8	)		5.1			(3.5	)
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		0.0			0.0			(1.0	)		0.4

Accumulated other comprehensive income (loss) before regulatory deferrals		(4.0	)		(1.8	)		5.1			(7.7	)
Regulatory deferral of costs to be recovered*		4.0			0.7			12.5			—

Accumulated other comprehensive income (loss) related to cash flow hedges – Sept. 30, 2003	$	0.0		$	(1.1	)	$	17.6		$	(7.7	)


	Nine Months Ended Sept. 30, 2002

(Millions of Dollars)	NSP-Minnesota			PSCo			SPS

Accumulated other comprehensive income (loss) related to cash flow hedges – Jan. 1, 2002	$	0.1		$	(4.3	)	$	(4.4	)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		(1.0	)		(5.4	)		0.4
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(0.1	)		9.7			(0.3	)
Regulatory deferral of costs to be recovered*		1.0			0.3			—

Accumulated other comprehensive income (loss) related to cash flow hedges – Sept. 30, 2002	$	0.0		$	0.3		$	(4.3	)

* In accordance with SFAS No. 71 - “Accounting for the Effects of Certain Types of Regulation,” certain costs/benefits have been deferred as they are expected to be recovered in future periods from customers.

Cash Flow Hedges

Xcel Energy’s Utility Subsidiaries enter into derivative instruments to manage variability of future cash flows from changes in commodity prices. These derivative instruments are designated as cash flow hedges for accounting purposes, and the changes in the fair value of these instruments are recorded as a component of Other Comprehensive Income. At Sept. 30, 2003, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS had various commodity-related contracts deemed as cash flow hedges extending through 2009. Amounts deferred in Other Comprehensive Income are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the physical purchase or sale of electric energy, the use of natural gas to generate electric energy or gas purchased for resale. As of Sept. 30, 2003, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS had no gains or losses accumulated in Other Comprehensive Income that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle. However, due to the volatility of commodities markets, the value in Other Comprehensive Income will likely change prior to its recognition in earnings.

PSCo recorded losses of $0 and $0.6 million related to ineffectiveness on commodity cash flow hedges during the three months ended Sept. 30, 2003 and 2002, respectively, and gains of $0 and $0.4 million related to ineffectiveness on commodity cash flow hedges during the nine months ended Sept. 30, 2003 and 2002, respectively.

SPS enters into interest rate swap instruments that effectively fix the interest payments on certain floating rate debt obligations. These derivative instruments are designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. SPS expects to reclassify into earnings during the next 12 months net losses from Other Comprehensive Income of approximately $2.1 million.

PSCo and NSP-Wisconsin enter into interest rate lock agreements that effectively fix the yield or price on a specified treasury security for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. PSCo expects to reclassify into earnings during the next 12 months net gains from Other Comprensive Income of approximately $1.5 million. NSP-Wisconsin expects to reclassify into earnings during the next 12 months net losses from other Comprehensive Income of approximately $0.1 million.

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

costs, hedging transactions for gas purchased for resale are recorded as a component of gas costs and hedging transactions for interest rate swaps and interest rate lock agreements are recorded as a component of interest expense. Certain Xcel Energy Utility Subsidiaries are allowed to recover in electric or gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.

Derivatives Not Qualifying for Hedge Accounting

NSP-Minnesota and PSCo have trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market basis in their respective Consolidated Statements of Operations. The results of these transactions are recorded within Operating Revenues on the Consolidated Statements of Operations.

Normal Purchases or Normal Sales Contracts

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

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

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

Accounting Changes

SFAS No. 149 - In April 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 149 — “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS No. 149), which amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies the discussion around initial net investment, clarifies when a derivative contains a financing component and amends the definition of an underlying to conform it to language used in FASB Interpretation No. 45. In addition, SFAS No. 149 also incorporates certain implementation issues of a derivative implementation group. The provisions of SFAS No. 149 have been applied to contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003.

SFAS No. 133 Implementation Issue No. C20 - In June 2003, for purposes of determining the applicability of the normal purchases and normal sales scope exception, the FASB issued SFAS No. 133 Implementation Issue No. C20 as supplemental guidance to SFAS No. 133 Implementation Issue No. C11. The effective date of the Implementation guidance of Issue No. C20 is the during fourth quarter of 2003 for Xcel Energy’s Utility Subsidiaries. The Utility Subsidiaries are currently in the process of reviewing and interpreting this guidance and do not currently anticipate any material adverse financial impact due to the implementation of Issue No. C20 guidance as a result of the ability to recover prudently-incurred purchased capacity costs from customers.

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

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

In 2003, the process to allocate common costs of the Electric and Natural Gas Utility segments was revised. Segment results for 2002 have been restated to reflect the revised cost allocation process.

NSP-Minnesota


			Electric		Natural Gas			All			Consolidated
(Thousands of Dollars)			Utility		Utility			Other			Total

Three months ended Sept. 30, 2003
Revenues from:
	External customers		$	756,629	$	54,338		$	(789	)	$	810,178
	Internal customers			181		4,028			—			4,209

		Total revenue		756,810		58,366			(789	)		814,387
Segment net income (loss)			$	90,314	$	(4,600	)	$	(5,304	)	$	80,410
Three months ended Sept. 30, 2002
Revenues from:
	External customers		$	713,946	$	31,184		$	6,836		$	751,966
	Internal customers			168		2			—			170

		Total revenue		714,114		31,186			6,836			752,136
Segment net income (loss)			$	95,072	$	(11,688	)	$	(392	)	$	82,992
Nine months ended Sept. 30, 2003
Revenues from:
	External customers		$	1,918,232	$	473,985		$	10,149		$	2,402,366
	Internal customers			528		6,509			—			7,037

		Total revenue		1,918,760		480,494			10,149			2,409,403
Segment net income (loss)			$	138,857	$	8,388		$	(2,743	)	$	144,502
Nine months ended Sept. 30, 2002
Revenues from:
	External customers		$	1,816,593	$	308,473		$	18,800		$	2,143,866
	Internal customers			463		31			—			494

		Total revenue		1,817,056		308,504			18,800			2,144,360
Segment net income			$	157,036	$	1,013		$	400		$	158,449

NSP-Wisconsin


			Electric		Natural Gas			All			Consolidated
(Thousands of Dollars)			Utility		Utility			Other			Total

Three months ended Sept. 30, 2003
Revenues from:
	External customers		$	129,177	$	6,983		$	(34	)	$	136,126
	Internal customers			30		2,322			—			2,352

		Total revenue		129,207		9,305			(34	)		138,478
Segment net income (loss)			$	14,644	$	(1,620	)	$	(745	)	$	12,279
Three months ended Sept. 30, 2002
Revenues from:
	External customers		$	121,539	$	8,213		$	541		$	130,293
	Internal customers			39		(100	)		—			(61	)

		Total revenue		121,578		8,113			541			130,232
Segment net income (loss)			$	14,017	$	(1,700	)	$	179		$	12,496
Nine months ended Sept. 30, 2003
Revenues from:
	External customers		$	357,680	$	86,663		$	103		$	444,446
	Internal customers			101		3,362			—			3,463

		Total revenue		357,781		90,025			103			447,909
Segment net income (loss)			$	35,492	$	2,286		$	(798	)	$	36,980
Nine months ended Sept. 30, 2002
Revenues from:
	External customers		$	348,564	$	66,752		$	652		$	415,968
	Internal customers			125		600			—			725

		Total revenue		348,689		67,352			652			416,693
Segment net income (loss)			$	41,322	$	2,170		$	(627	)	$	42,865

PSCo


			Electric		Natural Gas			All		Consolidated
(Thousands of Dollars)			Utility		Utility			Other		Total

Three months ended Sept. 30, 2003
Revenues from:
	External customers		$	588,016	$	111,151		$	4,354	$	703,521
	Internal customers			58		9			—		67

		Total revenue		588,074		111,160			4,354		703,588
Segment net income (loss)			$	58,164	$	(856	)	$	175	$	57,483
Three months ended Sept. 30, 2002
Revenues from:
	External customers		$	500,087	$	89,425		$	4,535	$	594,047
	Internal customers			74		5			—		79

		Total revenue		500,161		89,430			4,535		594,126
Segment net income			$	59,199	$	1,451		$	6,317	$	66,967
Nine months ended Sept. 30, 2003
Revenues from:
	External customers		$	1,575,108	$	529,462		$	15,723	$	2,120,293
	Internal customers			201		36			—		237

		Total revenue		1,575,309		529,498			15,723		2,120,530
Segment net income			$	115,146	$	40,761		$	5,317	$	161,224
Nine months ended Sept. 30, 2002
Revenues from:
	External customers		$	1,387,179	$	521,826		$	17,513	$	1,926,518
	Internal customers			194		32			—		226

		Total revenue		1,387,373		521,858			17,513		1,926,744
Segment net income			$	144,463	$	39,464		$	12,093	$	196,020

SPS

SPS operates in the regulated electric utility industry, providing wholesale and retail electric service in the states of Texas, New Mexico, Kansas and Oklahoma. Revenues from external customers were $380.5 million and $291.9 million for the three months ended Sept. 30, 2003 and 2002, respectively. Revenues from external customers were $909.4 million and $770.5 million for the nine months ended Sept. 30, 2003 and 2002, respectively.

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

NSP-Minnesota

The components of total comprehensive income are shown below:


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

(Millions of Dollars)			2003			2002			2003			2002

Net income			$	80.4		$	83.0		$	144.5		$	158.4
Other comprehensive income:
	After-tax net unrealized gains (losses) on derivatives accounted for as hedges (see Note 6)			(2.9	)		(1.6	)		(4.0	)		(1.0	)
		After-tax net realized (gains) losses on derivative transactions reclassified into earnings (see Note 6)		—			0.2			—			(0.1	)
		Regulatory deferral of costs to be recovered		2.9			1.0			4.0			1.0

Other comprehensive income (loss)				—			(0.4	)		—			(0.1	)

Comprehensive income			$	80.4		$	82.6		$	144.5		$	158.3

The accumulated comprehensive income in stockholder’s equity at Sept. 30, 2003 and 2002, relates to valuation adjustments on NSP-Minnesota’s derivative financial instruments and hedging activities, the related regulatory deferral and the mark-to-market components of NSP-Minnesota’s marketable securities.

NSP-Wisconsin

The components of total comprehensive income are shown below:


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

(Millions of Dollars)		2003			2002		2003			2002

Net income		$	12.3		$	12.5	$	37.0		$	42.9
Other comprehensive income:
	After-tax net unrealized gains (losses) on derivatives accounted for as hedges (see Note 6)		(1.6	)		—		(1.8	)		—
	Regulatory deferral of costs to be recovered		0.5			—		0.7			—

Other comprehensive income (loss)			(1.1	)		—		(1.1	)		—

Comprehensive income		$	11.2		$	12.5	$	35.9		$	42.9

The accumulated comprehensive income in stockholder’s equity at Sept. 30, 2003 and 2002, relates to valuation adjustments on NSP-Wisconsin’s derivative financial instruments and hedging activities, the related regulatory deferral and the mark-to-market components of NSP-Wisconsin’s marketable securities.

PSCo

The components of total comprehensive income are shown below:


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

(Millions of Dollars)			2003			2002			2003			2002

Net income			$	57.5		$	67.0		$	161.2		$	196.0
Other comprehensive income:
	After-tax net unrealized gains (losses) on derivatives accounted for as hedges (see Note 6)			8.8			(14.1	)		5.1			(5.4	)
	After-tax net realized (gains) losses on derivative transactions reclassified into earnings (see Note 6)			(0.9	)		14.8			(1.0	)		9.7
		Regulatory deferral of costs to be recovered		9.6			(0.1	)		12.5			0.3

Other comprehensive income				17.5			0.6			16.6			4.6

Comprehensive income			$	75.0		$	67.6		$	177.8		$	200.6

The accumulated comprehensive income in stockholder’s equity at Sept. 30, 2003 and 2002, relates to valuation adjustments on PSCo’s derivative financial instruments and hedging activities, the related regulatory deferral, the mark-to-market component of PSCo’s marketable securities and unrealized losses related to its minimum pension liability.

SPS

The components of total comprehensive income are shown below:


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

(Millions of Dollars)			2003			2002			2003			2002

Net income			$	38.1		$	31.7		$	67.1		$	59.9
Other comprehensive income:
	After-tax net unrealized gains (losses) on derivatives accounted for as hedges (see Note 6)			(0.8	)		(0.4	)		(3.5	)		0.4
	After-tax net realized (gains) losses on derivative transactions reclassified into earnings (see Note 6)			0.3			(0.4	)		0.4			(0.3	)
		Minimum pension liability		—			—			(24.5	)		—

Other comprehensive income (loss)				(0.5	)		(0.8	)		(27.6	)		0.1

Comprehensive income (loss)			$	37.6		$	30.9		$	39.5		$	60.0

The accumulated comprehensive income in Stockholder’s Equity at Sept. 30, 2003 and 2002, relates to valuation adjustments on SPS’ derivative financial instruments and hedging activities and unrealized losses related to its minimum pension liability.

9. Nuclear Fuel Storage - Prairie Island Legislation (NSP-Minnesota)

On May 29, 2003, the Minnesota Legislature enacted legislation, which will enable NSP-Minnesota to store at least 12 more casks of spent fuel outside the Prairie Island nuclear generating plant, allowing NSP-Minnesota to continue to operate the facility and store spent fuel there until the licenses with the NRC expire in 2013 and 2014. The legislation transfers from the state Legislature to the MPUC the primary authority concerning future spent-fuel storage issues and allows for additional storage of spent nuclear fuel in the event the NRC extends the licenses of Prairie Island and the Monticello Nuclear generating plant and the MPUC grants a certificate of need for such additional storage without the requirement of an affirmative vote from the state Legislature. The legislation requires Xcel Energy to add at least 300 megawatts of additional wind power by 2010 with an option to own 100 megawatts of this power.

The legislation also requires payments parties during the remaining operating life of the Prairie Island plant. These payments include: $2.25 million per year to the Prairie Island Tribal Community beginning in 2004; 5 percent of NSP-Minnesota’s conservation program expenditures (estimated at $2 million per year) to the University of Minnesota for renewable energy research; and an increase in funding commitments to the previously-established Renewable Development Fund from $8.5 million in 2002 to $16 million per year beginning in 2003. The legislation also designated $10 million in one-time grants to the University of Minnesota for additional renewable energy research, which is to be funded from commitments already made to the Renewable Development Fund. Nearly all of the cost increases to NSP-Minnesota from these required payments and funding commitments are expected to be recoverable in customer rates, mainly through existing cost recovery mechanisms. Funding commitments to the Renewable Development Fund would terminate after the Prairie Island plant discontinues operation unless the MPUC determines that Xcel Energy failed to make a good faith effort to move the waste, in which case NSP-Minnesota would have to make payments in the amount of $7.5 million per year.

10. Pension Plan Change and Impacts (SPS)

In April 2003, Xcel Energy amended certain of its retirement plans to provide the same level of benefits to all non-bargaining employees of its utility and service company operations. While this change did not have a material impact on 2003 costs for the affected pension and retiree health plans, the increased obligations resulting from the plan amendment did create a minimum pension liability, which was recorded in the second quarter of 2003. The additional pension obligation recorded by SPS increased noncurrent liabilities by approximately $21 million and reduced Accumulated Other Comprehensive Income, a component of shareholder’s equity, by approximately $25 million (net of related deferred tax effects of $14 million) during the quarter. The minimum pension liability adjustment also increased SPS’ noncurrent intangible assets by approximately $40 million due to the recording of unamortized prior service costs, and reduced its previously recorded prepaid pension assets accordingly.

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

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

Forward-Looking Information

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

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “estimate,” “expect,” “objective,” “outlook,” “possible,” “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:

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

• business conditions in the energy industry;

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

• unusual weather;

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

• the financial condition of affiliate, NRG;

• actions by the bankruptcy court relating to the NRG bankruptcy filing;

• risks related to investigations and enforcement actions by state and federal regulators;

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

• the other risk factors listed from time to time by the Utility Subsidiaries of Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to this Report on Form 10-Q for the quarter ended Sept. 30, 2003.

Financial Market Risks

The Utility Subsidiaries of Xcel Energy are exposed to market risks, including changes in commodity prices and interest rates as disclosed in Management’s Discussion and Analysis in their annual reports on Form 10-K for the year ended Dec. 31, 2002. Commodity price and interest rate risks for the Utility Subsidiaries of Xcel Energy are mitigated in most jurisdictions due to cost-based rate regulation. At Sept. 30, 2003, there were no material changes in the financial market risks that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2002, in Item 7A of their annual reports on Form 10-K. Value-at-risk, energy trading and hedging information is provided below for informational purposes.

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

Xcel Energy’s Utility Subsidiaries use a value-at-risk (VaR) model to assess the market risk of their fixed price purchase and sales commitments, physical forward contracts and commodity derivative instruments. VaR for commodity contracts, assuming a five-day holding period for electricity and a two-day holding period for natural gas, for the three months ended Sept. 30, 2003, is as follows:


			Change from
	Period Ended		Period Ended
(Millions of Dollars)	Sept. 30, 2003		June 30, 2003			VaR Limit		Average		High		Low

Electric Commodity
Trading (1)	$	0.82	$	(0.08	)	$	6.0	$	0.75	$	1.48	$	0.36

(1) Comprises transactions for both NSP-Minnesota and PSCo.

Energy Trading and Hedging Activities

Xcel Energy’s Utility Subsidiaries engage in energy trading activities that are accounted for in accordance with SFAS No. 133, as amended. The Utility Subsidiaries make wholesale purchases and sales of electricity, natural gas and related energy trading products in order to optimize the value of their electric generating facilities and retail supply contracts. Xcel Energy’s Utility Subsidiaries also engage in a limited number of wholesale commodity transactions. The Utility Subsidiaries utilize forward contracts for the purchase and sale of electricity and capacity, over-the-counter swap contracts, exchange-traded natural gas futures and options, transmission contracts, natural gas transportation contracts and other physical and financial contracts.

For the period ended Sept. 30, 2003, these contracts, with the exception of transmission and natural gas transportation contracts, which meet the definition of a derivative in accordance with SFAS 133, were marked to market. Changes in fair value of energy trading contracts that do not qualify for hedge accounting treatment are recorded in income in the reporting period in which they occur.

The changes to the fair value of the energy trading contracts for the three and nine months ended Sept. 30, 2003 and 2002 were as follows:


	Three months ended Sept. 30,

(Millions of Dollars)	2003			2002

Fair value of contracts outstanding at June 30	$	2.2		$	(1.1	)
Contracts realized or otherwise settled during the period		(3.2	)		5.4
Fair value of trading contract additions and changes during the period		11.5			(3.3	)

Fair value of contracts outstanding at Sept. 30	$	10.5		$	1.0


	Nine months ended Sept. 30,

(Millions of Dollars)	2003			2002

Fair value of contracts outstanding at Jan. 1	$	(0.1	)	$	7.4
Contracts realized or otherwise settled during the period		(5.5	)		(5.7	)
Fair value of trading contract additions and changes during the period		16.1			(0.7	)

Fair value of contracts outstanding at Sept. 30	$	10.5		$	1.0

As of Sept. 30, 2003, the sources of fair value of the energy trading and hedging net assets are as follows:

Trading Contracts


	Futures/Forwards

	Source of		Maturity Less			Maturity		Maturity		Maturity Greater		Total Futures/
(Thousands of Dollars)	Fair Value		Than 1 Year			1 to 3 Years		4 to 5 Years		Than 5 Years		Forwards Fair Value

NSP-Minnesota		1	$	(306	)	$	—	$	—	$	—	$	(306	)
		2		9,745			—		—		—		9,745
PSCo.		1		(440	)		—		—		—		(440	)
		2		1,442			—		—		—		1,442

Total Futures/Forwards Fair Value			$	10,441		$	—	$	—	$	—	$	10,441


	Options

	Source of		Maturity Less		Maturity		Maturity		Maturity Greater		Total Options Fair
(Thousands of Dollars)	Fair Value		Than 1 Year		1 to 3 Years		4 to 5 Years		Than 5 Years		Value

PSCo.		2	$	12	$	—	$	—	$	—	$	12

Total Options Fair Value			$	12	$	—	$	—	$	—	$	12

Hedge Contracts


	Futures/Forwards

	Source of		Maturity Less		Maturity		Maturity		Maturity Greater		Total Futures/
(Thousands of Dollars)	Fair Value		Than 1 Year		1 to 3 Years		4 to 5 Years		Than 5 Years		Forwards Fair Value

NSP-Minnesota		2	$	1,532	$	—	$	—	$	—	$	1,532
PSCo.		2		240		—		—		—		240

Total Futures/Forwards Fair Value			$	1,772	$	—	$	—	$	—	$	1,772


	Options

	Source of		Maturity Less			Maturity		Maturity		Maturity Greater		Total Options Fair
(Thousands of Dollars)	Fair Value		Than 1 Year			1 to 3 Years		4 to 5 Years		Than 5 Years		Value

NSP-Minnesota		2	$	(6,788	)	$	—	$	—	$	—	$	(6,788	)
NSP-Wisconsin		2		(1,106	)		—		—		—		(1,106	)
PSCo.		2		(22,967	)		695						(22,272	)

Total Options Fair Value			$	(30,861	)	$	695	$	—	$	—	$	(30,166	)

1 - Prices actively quoted or based on actively quoted prices.

2 - Prices based on models and other valuation methods. These represent the fair value of positions calculated using internal models when directly and indirectly quoted external prices or prices derived from external sources are not available. Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms. The models reflect management’s estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of energy commodity prices and contractual volumes. Market price uncertainty and other risks also are factored into the model.

In the above tables, only “hedge” transactions are included for NSP-Minnesota, NSP-Wisconsin and PSCo. “Normal purchases and sales” transactions have been excluded.

NSP-MINNESOTA MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

NSP-Minnesota’s net income was approximately $144.5 million for the first nine months of 2003, compared with approximately $158.4 million for the first nine months of 2002.

Electric Utility and Commodity Trading Margins

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

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

The following table details electric utility, short-term wholesale and electric commodity trading revenue and margin:


	Base						Electric
	Electric			Short-Term			Commodity			Consolidated
(Millions of Dollars)	Utility			Wholesale			Trading			Total

Nine months ended Sept. 30, 2003
Electric utility revenue	$	1,811		$	98		$	—		$	1,909
Electric fuel and purchased power		(631	)		(51	)		—			(682	)
Electric trading revenue		—			—			61			61
Electric trading costs		—			—			(51	)		(51	)

Gross margin before operating expenses	$	1,180		$	47		$	10		$	1,237

Margin as a percentage of revenue		65.2	%		48.0	%		16.4	%		62.8	%
Nine months ended Sept. 30, 2002
Electric utility revenue	$	1,748		$	71		$	—		$	1,819
Electric fuel and purchased power		(566	)		(47	)		—			(613	)
Electric trading revenue		—			—			24			24
Electric trading costs		—			—			(26	)		(26	)

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

Margin as a percentage of revenue		67.6	%		33.8	%		(8.3	)%		65.3	%

Base electric utility revenues increased by $63 million, or 3.6 percent, in the first nine months of 2003, compared with the same period in 2002. Base electric utility margins decreased by $2 million, or 0.2 percent in the first nine months of 2003 when compared with the same period in 2002. The increase in revenues reflects sales growth and the recovery in 2003 of increased electric fuel costs and of $14 million in renewable development fund payments (for which a corresponding charge to depreciation expense was recorded), through the fuel clause mechanism and interchange agreement with NSP-Wisconsin. Also, transmission revenue increased in 2003. These increases were partially offset by the impact of an electric rate reduction attributable to a Minnesota state property tax reduction and unfavorable weather. The decrease in margins is attributable to the revenue increase being offset by increased demand costs, lower conservation incentives, lower revenues from sales of capacity options and a 2003 true-up to the interchange agreement related to 2002.

Short-term wholesale margins increased $23 million, or 96 percent, in the first nine months of 2003, compared with the first nine months of 2002, primarily due to more favorable market conditions.

Natural Gas Utility Margins

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


	Nine Months Ended Sept. 30,

(Millions of Dollars)	2003			2002

Natural gas utility revenue	$	480		$	309
Cost of natural gas sold and transported		(368	)		(210	)

Natural gas utility margin	$	112		$	99

Natural gas revenue increased by approximately $171 million, or 55.3 percent, in the first nine months of 2003, primarily due to significant increases in the cost of natural gas, which are largely passed on to customers through various rate adjustment clauses. Natural gas margin for the first nine months of 2003 increased by $13 million, or 13.1 percent, compared with the first nine months of 2002, primarily due to sales growth, favorable weather in 2003 and true-ups to the purchased gas adjustment.

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expense increased by approximately $36.7 million, or 6.1 percent, for the first nine months of 2003, compared with the first nine months of 2002, primarily due to two planned refueling outages at nuclear plants in 2003 compared with one refueling outage in 2002 and outages at combustion and hydro plants as well as higher incentive and other employee benefit costs.

Depreciation and Amortization Expense increased by approximately $22.6 million, or 8.6 percent, for the first nine months of 2003, compared with the first nine months of 2002, primarily due to $14 million of renewable development fund costs, which are largely recovered through NSP-Minnesota’s fuel clause mechanism and the interchange agreement with NSP-Wisconsin. Depreciation also increased due to computer software additions.

As discussed in Note 2 to the consolidated financial statements, in the first quarter of 2002, pretax special charges of $4.3 million were expensed for the costs of staff consolidations. The charges related to severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy.

Other Income (Expense) - net decreased by $6.3 million, due primarily to a gain on the sale of property by a subsidiary of NSP-Minnesota, First Midwest Auto Park, in March 2002 and interest income of $7 million from a state and federal income tax settlements recorded in June and August 2002. These decreases from 2002 were partially offset by higher allowances for funds used during construction in 2003.

Interest charges and financing costs increased by approximately $24.9 million, or 32.2 percent, for the first nine months of 2003, compared with the first nine months of 2002. The increase is due to the issuance of long-term debt in July and August of 2002, as part of a financing plan to reduce the dependence on short-term debt.

Income tax expense decreased by approximately $36.7 million for the first nine months of 2003, compared with the first nine months of 2002. The effective tax rate for NSP-Minnesota was 32 percent in the first nine months of 2003 and 40 percent in the same period of 2002. The change in the effective tax rate between years primarily reflects adjustments recorded in 2003 related to updated income apportionment by state for 2002 and 2003, a higher ratio of tax credits to lower income levels and adjustments due to favorable income tax audit settlements in 2003.

NSP-WISCONSIN MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

NSP-Wisconsin’s net income was $37.0 million for the first nine months of 2003, compared with $42.9 million for the first nine months of 2002.

Electric Utility Margins

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


	Nine Months Ended Sept. 30,

(Millions of Dollars)	2003			2002

Total electric utility revenue	$	358		$	349
Electric fuel and purchased power		(175	)		(160	)

Total electric utility margin	$	183		$	189

Margin as a percentage of revenue		51.1	%		54.2	%

Electric Utility revenue increased by approximately $9.1 million or 2.6 percent for the first nine months of 2003 due to sales growth and higher billings to NSP-Minnesota for cost allocations. Electric utility margin decreased by approximately $6 million, or 3.2 percent, in the first nine months of 2003, compared with the first nine months of 2002, primarily due to lower fuel cost recovery through rates and higher unit costs of fuel and purchased power in 2003. Sales growth and higher billings to NSP-Minnesota for cost allocations partially offset the margin decreases.

Natural Gas Utility Margins

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


	Nine Months Ended Sept. 30,

(Millions of Dollars)	2003			2002

Natural gas revenue	$	90		$	67
Cost of natural gas sold and transported		(68	)		(47	)

Natural gas utility margin	$	22		$	20

Natural gas revenue for the first nine months of 2003 increased by approximately $23 million, or 33.7 percent, compared with the first nine months of 2002, primarily due to significant increases in the cost of natural gas, which is largely recovered through various purchased natural gas cost recovery mechanisms. Natural gas margin increased by approximately $2 million, or 11.8 percent, in the first nine months of 2003 due to a higher-revenue mix of sales volumes and more favorable weather conditions in 2003.

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expense for the first nine months of 2003 increased by approximately $3.0 million, or 3.9 percent, compared with the first nine months of 2002, primarily due to higher incentive and other benefit costs partially offset by lower transmission interchange charges from NSP-Minnesota.

Depreciation and Amortization Expense increased by approximately $1.8 million, or 5.3 percent, in the first nine months of 2003, compared with the first nine months of 2002, primarily due to capital additions to utility plant.

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

PSCo’s MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

PSCo’s net income was $161.2 million for the first nine months of 2003, compared with $196.0 million for the first nine months of 2002.

Electric Utility and Commodity Trading Margins

Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel clause cost recovery mechanisms for retail customers in Colorado, most fluctuations in energy costs do not materially affect electric margin. In addition to energy cost recovery mechanisms, PSCo has other adjustment clauses that allow certain costs to be recovered from retail customers.

Some electric commodity trading activity, initially recorded at PSCo, is partially redistributed to NSP-Minnesota and SPS pursuant to the JOA approved by the FERC. Trading revenue and costs do not include the revenue and production costs associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Margins from these generating assets for utility operations are included in short-term wholesale amounts. If applicable, trading margins reflect the impact of sharing certain trading margins with Colorado retail customers.

The following table details electric utility, short-term wholesale and electric trading revenue and margin.


	Base						Electric
	Electric			Short-Term			Commodity			Consolidated
(Millions of Dollars)	Utility			Wholesale			Trading			Total

Nine months ended Sept. 30, 2003
Electric utility revenue	$	1,535		$	40		$	—		$	1,575
Electric fuel and purchased power		(813	)		(43	)		—			(856	)
Electric trading revenue		—			—			191			191
Electric trading costs		—			—			(190	)		(190	)

Gross margin before operating expenses	$	722		$	(3	)	$	1		$	720

Margin as a percentage of revenue		47.0	%		(7.5	)%		0.5	%		40.8	%
Nine months ended Sept. 30, 2002
Electric utility revenue	$	1,331		$	56		$	—		$	1,387
Electric fuel and purchased power		(582	)		(56	)		—			(638	)
Electric trading revenue		—			—			1,327			1,327
Electric trading costs		—			—			(1,327	)		(1,327	)

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

Margin as a percentage of revenue		56.3	%		—	%		—	%		27.6	%

Base electric utility revenues increased approximately $204 million, or 15.3 percent, in the first nine months of 2003 compared with the first nine months of 2002 due mainly to higher levels of cost recovery under PSCo’s Interim Adjustment Clause, Air Quality Improvement Rider (AQIR), and Incentive Cost Adjustment Clause (which are provisions in PSCo’s electric rates that allow it to recover certain costs that differ from the costs included in its base rates) in 2003, and to sales growth.

Base electric utility margin decreased by approximately $27 million, or 3.6 percent, in the first nine months of 2003, compared with the first nine months of 2002. The lower base electric margins reflect higher demand costs and unfavorable weather, partially offset by higher sales growth and the implementation of an AQIR for the recovery of investments and related costs to improve air quality in Colorado.

Natural Gas Utility Margins

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


	Nine Months Ended Sept. 30,

(Millions of Dollars)	2003			2002

Natural gas revenue	$	529		$	522
Cost of natural gas sold and transported		(311	)		(294	)

Natural gas utility margin	$	218		$	228

Natural gas revenue for the first nine months of 2003 increased by approximately $7 million, or 1.3 percent, compared with the first nine months of 2002, largely due to higher levels of cost recovery under the GCA. Natural gas margin for the first nine months of 2003 decreased by approximately $10 million, or 4.4 percent, compared with the first nine months of 2002, primarily due to rate reductions resulting from the 2002 rate case, and warmer winter weather in 2003.

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expense increased approximately $14.2 million, or 4.2 percent, for the first nine months of 2003 compared with the first nine months of 2002. The increased costs are due to higher incentive and employee benefit costs, partly offset by lower information technology related costs and lower plant outage related costs.

Depreciation and Amortization Expense decreased by approximately $14 million, or 7.5 percent, for the first nine months of 2003 compared with the first nine months of 2002, primarily due to decreased amortization of capitalized software and to depreciation of Arapahoe plant units 1 and 2, which ended Dec. 31, 2002.

Interest charges and financing costs increased by approximately $15 million, or 14.2 percent, for the first nine months of 2003 compared with the first nine months of 2002. The increase was largely due to the issuance of $600 million of 7.875 percent bonds in September 2002.

Income tax expense decreased by $24 million for the first nine months of 2003 compared with the same period in 2002. The effective tax rate for PSCo was 31.2 percent in the first nine months of 2003 compared with 33.1 percent for the same period in 2002. The change in the expense between years is due primarily to lower pretax income, and the lower effective tax rate reflects a higher ratio of tax credits to lower income levels in 2003.

SPS’ MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

SPS’ net income was approximately $67.1 million for the first nine months of 2003, compared with approximately $59.9 million for the first nine months of 2002.

Electric Utility Margins

The following table details the change in electric revenue and margin. Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel clause cost recovery mechanisms for retail customers, most fluctuations in energy costs do not affect electric margin.


	Base
	Electric			Short-Term			Consolidated
(Millions of Dollars)	Utility			Wholesale			Total

Nine months ended Sept. 30, 2003
Electric utility revenue	$	904		$	5		$	909
Electric fuel and purchased power		(539	)		(4	)		(543	)

Gross margin before operating expenses	$	365		$	1		$	366

Margin as a percentage of revenue		40.4	%		20.0	%		40.3	%


	Base
	Electric			Short-Term			Consolidated
(Millions of Dollars)	Utility			Wholesale			Total

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

Gross margin before operating expenses	$	356		$	—		$	356

Margin as a percentage of revenue		46.4	%		—	%		46.2	%

Base electric utility revenue increased by approximately $137 million, or 17.9 percent, for the first nine months of 2003, compared with the first nine months of 2002. Base electric utility margin increased by approximately $9 million, or 2.5 percent, for the first nine months of 2003, compared with the first nine months of 2002. Base electric revenues increased primarily due to higher fuel and purchased power costs recovered through electric rates, higher sharing of commodity trading margins with PSCo and NSP-Minnesota through the JOA, partially offset by the unfavorable effects of lower average temperatures. The increase in base electric margin was primarily due to the effects of higher capacity sales, and higher revenues shared through the JOA, partially offset by the settlement impacts of the Texas fuel cost recovery proceeding, and the unfavorable effects of lower average temperatures.

Non-Fuel Operating Expense and Other Costs

Other Operating and Maintenance Expense increased by approximately $9.6 million, or 8.5 percent, for the first nine months of 2003 compared with the first nine months of 2002. The increased costs are due to higher incentive and other employee benefit costs partly offset by lower outage related costs.

Taxes Other Than Income Taxes decreased by approximately $4.8 million, or 11.9 percent, for the first nine months of 2003, compared with the first nine months of 2002. The decrease is primarily due to a lower assessed franchise tax rate within Texas for 2003.

As discussed in Note 2 to the Financial Statements, in late 2001 SPS filed an application requesting a rate rider to recover costs incurred to comply with transition to retail competition legislation in Texas and New Mexico. During the first quarter of 2002, SPS entered into a settlement agreement with intervenors regarding the recovery of restructuring costs in Texas, subject to approval by the state regulatory commission. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million in 2002, which are reported as special charges.

Item 4. CONTROLS AND PROCEDURES

Xcel Energy’s Utility Subsidiaries maintain a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that are filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of the Utility Subsidiaries’ management, including the Chief Executive Officers (CEO) and Chief Financial Officers (CFO) of such Utility Subsidiaries, of the effectiveness of our disclosure controls and procedures, the CEO and CFO of each Utility Subsidiary have concluded that such Utility Subsidiaries’ disclosure controls and procedures are effective.

No change in the Utility Subsidiaries’ internal control over financial reporting has occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Utility Subsidiaries’ internal controls over financial reporting.

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

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against the Utility Subsidiaries of Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. See Notes 3 and 4 to the consolidated financial statements in this Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 of NSP-Minnesota’s, NSP-Wisconsin’s, PSCo’s and SPS’ 2002 Form 10-K for a description of certain legal proceedings presently pending. There are no new significant cases to report against the Utility Subsidiaries of Xcel Energy and there have been no notable changes in the previously reported proceedings, except as set forth below.

NSP-Minnesota

Under a 1996 data services agreement, SchlumbergerSema, Inc. (SLB) provides automated meter reading, distribution automation, and other data services to NSP-Minnesota. In September 2002, NSP-Minnesota issued written notice that SLB committed events of default under the agreement, including SLB’s nonpayment of approximately $7.4 million for distribution automation assets. In November 2002, SLB demanded arbitration and asserted various claims against NSP-Minnesota totaling $24 million for alleged breach of an expansion contract and a meter purchasing contract. In the arbitration, NSP-Minnesota asserts counterclaims against SLB for SLB’s failure to meet performance criteria, improper billing, failure to pay for use of NSP-Minnesota owned property and failure to pay $7.4 million for NSP-Minnesota distribution automation assets. NSP-Minnesota also seeks a declaratory judgment from the arbitrator that will terminate SLB’s rights under the DSA. The parties are scheduled to arbitrate the dispute beginning March 1, 2004.

As discussed previously in the Form 10-K for the period ending Dec. 31, 2002, 25 lawsuits have been filed as a result of a Dec. 11, 1998 gas explosion that killed four persons (including two employees of NSP-Minnesota), injured several others and damaged numerous buildings. Most of the lawsuits name as defendants, NSP-Minnesota, Seren, Cable Constructors, Inc. (CCI) (the contractor that struck the marked gas line) and Sirti, an architectural/engineering firm hired by Seren for its St. Cloud cable installation project. Recently, the court granted the plaintiffs’ request to amend the complaint to seek punitive damages against Seren and CCI. The

plaintiffs brought a similar motion against NSP-Minnesota. On Oct. 23, 2003, the court denied plaintiffs’ motion. A trial date has been scheduled for Jan. 6, 2004.

NSP-Wisconsin

On Sept. 25, 2000, NSP-Wisconsin was served with a complaint in Eau Claire County Circuit Court, Wisconsin, on behalf of Claron and Janice Stubrud. The complaint alleged that stray voltage from NSP-Wisconsin’s system harmed their dairy herd resulting in lost milk production, lost profits and income, property damage, and injury to their dairy herd. The complaint also alleged that NSP-Wisconsin acted willfully and wantonly, entitling plaintiffs to treble damages. The plaintiffs alleged farm damages of approximately $3.8 million, $2.7 million of which represents prejudgment interest. On March 28, 2003, the trial court granted partial summary judgment to NSP-Wisconsin and dismissed plaintiffs’ claims for strict products liability, trespass, treble damages, and prejudgment interest. This case was resolved in August 2003, with no material impact to NSP-Wisconsin.

On July 28, 2003, James and Elaine Nigon, defendants in a real estate misrepresentation suit commenced in Clark County Circuit Court by Dennis and Kathy Weber, served NSP-Wisconsin with a third-party summons and complaint. The Webers purchased a dairy farm from the Nigons in June 2000, and allege that the Nigons misrepresented the existence of stray voltage problems at the farm. The Nigons have joined NSP-Wisconsin as a third-party defendant, alleging that if they are liable to plaintiffs, it is as a result of their reliance on NSP-Wisconsin’s representations regarding stray voltage levels at the farm. NSP-Wisconsin is not aware of the amount of damages being claimed by the Webers. A final pretrial hearing has been set for May 7, 2004, at which time a trial date will be determined.

SPS

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

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

The following Exhibits are filed with this report:

* Indicates incorporation by reference.


4.01*		Third Supplemental Indenture dated Oct. 1, 2003 between SPS and JPMorgan Chase Bank, as successor Trustee, creating $100 million principal amount of series C senior notes, 6 percent due 2033. (Filed as Exhibit 4.04 to Xcel Energy’s Form 10-Q report (File No. 1-3034) for the third quarter of 2003 and incorporated herein by reference.)

4.02*		Supplemental Trust Indenture dated Sept. 1, 2003 between NSP-Wisconsin and U.S. Bank National Association, as Trustee, creating $150 million principal amount of 5.25 percent first mortgage bonds, series due Oct. 1, 2018. (Filed as Exhibit 4.05 to Xcel Energy’s Form 10-Q report (File No. 1-3034) for the third quarter of 2003 and incorporated herein by reference.)

4.03*		Supplemental Indenture dated as of Sept. 1. 2003 between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating an Issue of First Mortgage Bonds, Collateral Series N and an Issue of First Mortgage Bonds, Collateral Series O. (Filed as Exhibit 4.01 to PSCo’s Form 8-K report (File No. 001-3280) dated Sept. 2, 2003 and incorporated herein by reference.)

4.04*		Supplemental Indenture No. 15 dated as of Sept. 1. 2003 between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating $300 million principal amount of 4.375 percent First Collateral Trust Bonds, Series No. 14 due


		2008 and $275 million principal amount of 5.50 percent First collateral Trust bonds, Series No. 15 due 2014. (Filed as Exhibit 4.02 to PSCo’s Form 8-K report (File No. 001-3280) dated Sept. 2, 2003 and incorporated herein by reference.)

4.05*		Supplemental Indenture dated as of Aug. 1. 2003 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $200 million principal amount of 2.875 percent First Mortgage Bonds, Series due Aug. 1, 2006 and $165 million principal amount of 4.750 percent First Mortgage Bonds, Series due Aug. 1, 2010. (Filed as Exhibit 4.01 to NSP-Minnesota’s Form 8-K report (File No. 001-31387) dated Aug. 4, 2003 and incorporated herein by reference.)

31.01		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - NSP-Minnesota.

31.02		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - NSP-Wisconsin.

31.03		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - PSCo.

31.04		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - SPS.

32.01		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - NSP-Minnesota.

32.02		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - NSP-Wisconsin.

32.03		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - PSCo.

32.04		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - SPS.

99.01		Statement pursuant to Private Securities Litigation Reform Act.

(b) Reports on Form 8-K

The following reports on Form 8-K were filed either during the three months ended Sept. 30, 2003, or between Sept. 30, 2003, and the date of this report:

NSP-Minnesota

Aug. 4, 2003 (filed Aug. 6, 2003) Items 5 and 7 Other Events and Financial Statements and Exhibits - Re: Prospectus supplement relating to $200 million of 2.875 percent First Mortgage Bonds due Aug. 1, 2006 and $175 million of 4.750 percent First Mortgage Bonds due Aug. 1, 2010.

Sept. 24, 2003 (filed Sept. 24, 2003) – Items 5 and 7 Other Events and Financial Statements and Exhibits – Re: announce a settlement agreement with the Minnesota Attorney General and Minnesota Department of Commerce in their investigation into power outage reporting.

NSP-Wisconsin

Sept. 29, 2003 (filed Sept. 29, 2003) – Items 5 and 7 Other Events and Financial Statements and Exhibits – Re: publish excerpts from an offering circular prepared for the issue of long term debt by NSP-Wisconsin.

PSCo

March 7, 2003 (amendment filed Sept. 2, 2003) - Items 5 and 7 Other Events and Financial Statements and Exhibits – Re: to remove references to “EBITDA”, a non-GAAP financial statistic, presented under the “Selected Consolidated Financial Data” caption.

Sept. 2, 2003 (filed Sept. 4, 2003) - Items 5 and 7 Other Events and Financial Statements and Exhibits – Re: PSCo entered into an underwriting agreement relating to a $300 million issue of debt and a $275 million issue of debt.

Sept. 4, 2003 (filed Sept. 8, 2003) - Items 5 and 7 Other Events and Financial Statements and Exhibits – Re: PSCo filed a prospectus supplement relating to a $300 million issue of debt and a $275 million issue of debt.

SPS

Oct. 1, 2003 (filed Oct. 3, 2003) - Items 5 and 7 Other Events and Financial Statements and Exhibits – Re: publish excerpts from an offering circular prepared for the issue of long-term debt by SPS.

NORTHERN STATES POWER CO. (A MINNESOTA CORPORATION) SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on Nov. 13, 2003.


		Northern States Power Co. (a Minnesota corporation)

		(Registrant)

		/s/ DAVID E. RIPKA

		David E. Ripka
		Vice President and Controller

		/s/ BENJAMIN G.S. FOWKE III

		Benjamin G.S. Fowke III
		Vice President, Chief Financial Officer and Treasurer

NORTHERN STATES POWER CO. (A WISCONSIN CORPORATION) SIGNATURES


		Northern States Power Co. (a Wisconsin corporation)

		(Registrant)

		/s/ DAVID E. RIPKA

		David E. Ripka
		Vice President and Controller

		/s/ BENJAMIN G.S. FOWKE III

		Benjamin G.S. Fowke III
		Vice President, Chief Financial Officer and Treasurer

PUBLIC SERVICE CO. OF COLORADO SIGNATURES


		Public Service Co. of Colorado

		(Registrant)

		/s/ DAVID E. RIPKA

		David E. Ripka
		Vice President and Controller

		/s/ BENJAMIN G.S. FOWKE III

		Benjamin G.S. Fowke III
		Vice President, Chief Financial Officer and Treasurer

SOUTHWESTERN PUBLIC SERVICE CO. SIGNATURES


		Southwestern Public Service Co.

		(Registrant)

		/s/ DAVID E. RIPKA

		David E. Ripka
		Vice President and Controller

		/s/ BENJAMIN G.S. FOWKE III

		Benjamin G.S. Fowke III Vice President, Chief Financial Officer and Treasurer

The following Exhibits are filed with this report:

* Indicates incorporation by reference.

EXHIBIT INDEX


EXHIBIT NUMBER		DESCRIPTION

4.01*		Third Supplemental Indenture dated Oct. 1, 2003 between SPS and JPMorgan Chase Bank, as successor Trustee, creating $100 million principal amount of series C senior notes, 6 percent due 2033. (Filed as Exhibit 4.04 to Xcel Energy’s Form 10-Q report (File No. 1-3034) for the third quarter of 2003 and incorporated herein by reference.)

4.02*		Supplemental Trust Indenture dated Sept. 1, 2003 between NSP-Wisconsin and U.S. Bank National Association, as Trustee, creating $150 million principal amount of 5.25 percent first mortgage bonds, series due Oct. 1, 2018. (Filed as Exhibit 4.05 to Xcel Energy’s Form 10-Q report (File No. 1-3034) for the third quarter of 2003 and incorporated herein by reference.)

4.03*		Supplemental Indenture dated as of Sept. 1. 2003 between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating an Issue of First Mortgage Bonds, Collateral Series N and an Issue of First Mortgage Bonds, Collateral Series O. (Filed as Exhibit 4.01 to PSCo’s Form 8-K report (File No. 001-3280) dated Sept. 2, 2003 and incorporated herein by reference.)

4.04*		Supplemental Indenture No. 15 dated as of Sept. 1. 2003 between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating $300 million principal amount of 4.375 percent First Collateral Trust Bonds, Series No. 14 due 2008 and $275 million principal amount of 5.50 percent First collateral Trust bonds, Series No. 15 due 2014. (Filed as Exhibit 4.02 to PSCo’s Form 8-K report (File No. 001-3280) dated Sept. 2, 2003 and incorporated herein by reference.)

4.05*		Supplemental Indenture dated as of Aug. 1. 2003 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $200 million principal amount of 2.875 percent First Mortgage Bonds, Series due Aug. 1, 2006 and $165 million principal amount of 4.750 percent First Mortgage Bonds, Series due Aug. 1, 2010. (Filed as Exhibit 4.01 to NSP-Minnesota’s Form 8-K report (File No. 001-31387) dated Aug. 4, 2003 and incorporated herein by reference.)

31.01		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - NSP-Minnesota.

31.02		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - NSP-Wisconsin.

31.03		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - PSCo.

31.04		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - SPS.

32.01		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - NSP-Minnesota.

32.02		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - NSP-Wisconsin.

32.03		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - PSCo.

32.04		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - SPS.

99.01		Statement pursuant to Private Securities Litigation Reform Act.

	•		$1 million in refunds to Minnesota customers who have experienced the longest duration of outages, which have been accrued at Sept. 30, 2003;

	•		additional actions to improve system reliability in an effort to reduce outage frequency and duration. These actions will target the primary outage causes, including tree trimming and cable replacement. At least an additional $15 million, above amounts being currently recovered in rates, is to be spent in Minnesota on these outage prevention improvements by Jan. 1, 2005; and

	•		development of a revised service quality plan containing a standard for service outage documentation, new performance measures, new thresholds for current performance measures and a new structure for consequences that will result from failure to meet these performance measures.

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

	•		an interim adjustment clause (IAC) that recovers 100 percent of prudently incurred 2003 electric fuel and purchased energy expense above the expense recovered through electric base rates during 2003. This clause is projected to recover energy costs totaling approximately $216 million in 2003;

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

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

	•		maintenance of an equity ratio of 43.74 percent to 53.46 percent;

	•		payment of dividends only from retained earnings; and

	•		debt covenant restrictions under the credit agreement for debt and interest coverage ratios.

	•		maintenance of an equity ratio of 52 percent to 57 percent; and

	•		payment of dividends only from retained earnings.

	•		maintenance of a minimum equity ratio of 30 percent;

	•		payment of dividends only from retained earnings; and

	•		debt covenant restrictions under the credit agreement for debt and interest coverage ratios.

	•		instruments that represent, or are indexed to, an obligation to buy back the issuer’s shares, regardless of whether the instrument is settled on a net-cash or gross physical basis;

	•		mandatorily redeemable equity instruments;

	•		written options that give the counterparty the right to require the issuer to buy back shares; and

	•		forward contracts that require the issuer to purchase shares.

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

	•		business conditions in the energy industry;

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

	•		unusual weather;

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

	•		the financial condition of affiliate, NRG;

	•		actions by the bankruptcy court relating to the NRG bankruptcy filing;

	•		risks related to investigations and enforcement actions by state and federal regulators;

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

	•		the other risk factors listed from time to time by the Utility Subsidiaries of Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to this Report on Form 10-Q for the quarter ended Sept. 30, 2003.