NORTHERN STATES POWER CO - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


(Mark One)
x		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the quarterly period ended March 31, 2004

		OR

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

		For the transition period from _______ to _______


	Exact name of registrant as specified
	in its charter, State or
	other jurisdiction of incorporation or
	organization, Address of
	principal executive offices and
Commission	Registrant's Telephone Number,	IRS Employer
File Number	including area code	Identification No.
001-31387	NORTHERN STATES POWER COMPANY	41-1967505
	(a Minnesota Corporation)
	414 Nicollet Mall, Minneapolis, Minn. 55401
	Telephone (612) 330-5500

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

001-03280	PUBLIC SERVICE COMPANY OF COLORADO	84-0296600
	(a Colorado Corporation)
	1225 17th Street, Denver, Colo. 80202 Telephone (303) 571-7511

001-03789	SOUTHWESTERN PUBLIC SERVICE COMPANY	75-0575400
	(a New Mexico Corporation)
	Tyler at Sixth, Amarillo, Texas 79101
	Telephone (303) 571-7511

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

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

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


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

Table of Contents


	PART I - FINANCIAL INFORMATION
Item l.	Financial Statements	3
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	23
	PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	34
Item 6.	Exhibits and Reports on Form 8-K	34
Certifications Pursuant to Section 302 - NSP-MN
Certifications Pursuant to Section 302 - NSP-WI
Certifications Pursuant to Section 302 - PSCo.
Certifications Pursuant to Section 302 - SPS
Certifications Pursuant to Section 906 - NSP-MN
Certifications Pursuant to Section 906 - NSP-WI
Certifications Pursuant to Section 906 - PSCo.
Certifications Pursuant to Section 906 - SPS
Statement - Private Securities Litigation Act

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 on various filings with the Securities and Exchange Commission (SEC).

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

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

PART 1. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

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


	Three Months Ended March 31
	2004			2003
Operating revenues:
Electric utility	$	608,316		$	586,911
Electric trading margin		1,351			1,400
Natural gas utility		312,132			333,250
Other		7,863			6,194

Total operating revenues		929,662			927,755
Operating expenses:
Electric fuel and purchased power		216,280			208,990
Cost of natural gas sold and transported		246,845			268,692
Other operating and maintenance expenses		207,495			211,610
Depreciation and amortization		82,166			91,202
Taxes (other than income taxes)		44,243			44,346

Total operating expenses		797,029			824,840

Operating income		132,633			102,915
Other income (expense):
Interest income		1,630			1,900
Other nonoperating income		3,287			2,600
Nonoperating expense		(1,335	)		(1,480	)

Total other income		3,582			3,020
Interest charges and financing costs:
Interest charges — net of amounts capitalized, includes other financing costs of $2,305 and $1,734, respectively		32,862			31,974
Distributions on redeemable preferred securities of subsidiary trust		—			3,938

Total interest charges and financing costs		32,862			35,912

Income before income taxes		103,353			70,023
Income taxes		34,996			25,572

Net income	$	68,357		$	44,451

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

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


	Three Months Ended March 31
	2004			2003
Operating activities:
Net income	$	68,357		$	44,451
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		85,461			93,533
Nuclear fuel amortization		11,596			11,791
Deferred income taxes		3,165			(10,395	)
Amortization of investment tax credits		(1,787	)		(1,841	)
Allowance for equity funds used during construction		(3,715	)		(2,009	)
Change in accounts receivable		(24,714	)		(62,091	)
Change in accounts receivable from affiliates		44,887			7,841
Change in inventories		34,645			25,375
Change in other current assets		26,502			(14,683	)
Change in accounts payable		(19,029	)		7,997
Change in other current liabilities		32,275			3,775
Change in other noncurrent assets		13,685			1,261
Change in other noncurrent liabilities		16,397			14,217

Net cash provided by operating activities		287,725			119,222
Investing activities:
Capital/construction expenditures		(121,502	)		(90,564	)
Proceeds from sale of property		—			—
Allowance for equity funds used during construction		3,715			2,009
Investments in external decommissioning fund		(20,145	)		(8,406	)
Other investments — net		(922	)		(1,638	)

Net cash used in investing activities		(138,854	)		(98,599	)
Financing activities:
Short-term borrowings — net		(58,000	)		(2	)
Repayment of long-term debt, including reacquisition premiums		(54	)		(107,790	)
Capital contribution from parent		50,000			—
Dividends paid to parent		(53,852	)		(52,280	)

Net cash used in financing activities		(61,906	)		(160,072	)
Net increase (decrease) in cash and cash equivalents		86,965			(139,449	)
Cash and cash equivalents at beginning of year		82,015			310,338

Cash and cash equivalents at end of year	$	168,980		$	170,889

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

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


	March 31			Dec. 31
	2004			2003
ASSETS
Current assets:
Cash and cash equivalents	$	168,980		$	82,015
Accounts receivable — net of allowance for bad debts: $7,052 and $7,581, respectively		302,860			278,146
Accounts receivable from affiliates		27,639			72,526
Accrued unbilled revenues		106,033			125,872
Materials and supplies inventories at average cost		99,722			100,297
Fuel inventory — at average cost		30,494			27,727
Natural gas inventory — at average cost		6,642			43,479
Income tax receivable		—			11,249
Derivative instrument valuation at market		35,421			26,666
Prepayments and other		33,616			30,011

Total current assets		811,407			797,988

Property, plant and equipment, at cost:
Electric utility plant		7,350,890			7,268,609
Natural gas utility plant		757,049			746,835
Construction work in progress		335,961			328,880
Other		417,386			400,448

Total property, plant and equipment		8,861,286			8,744,772
Less accumulated depreciation		(4,064,301	)		(3,991,875	)
Nuclear fuel – net of accumulated amortization: $1,113,528 and $1,101,932, respectively		71,505			80,289

Net property, plant and equipment		4,868,490			4,833,186

Other assets:
Nuclear decommissioning fund investments		835,836			779,382
Other investments		25,419			25,055
Regulatory assets		431,262			492,491
Prepaid pension asset		328,661			317,956
Derivative instrument valuation at market		256,044			177,581
Other		53,146			59,463

Total other assets		1,930,368			1,851,928

Total assets	$	7,610,265		$	7,483,102

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	4,501		$	4,502
Short-term debt		—			58,000
Accounts payable		205,276			250,628
Accounts payable to affiliates		59,207			32,884
Taxes accrued		170,989			116,862
Accrued interest		24,879			44,485
Dividends payable to parent		52,294			53,852
Derivative instrument valuation at market		53,940			67,664
Other		41,107			44,863

Total current liabilities		612,193			673,740

Deferred credits and other liabilities:
Deferred income taxes		754,852			738,677
Deferred investment tax credits		64,790			66,681
Regulatory liabilities		921,501			889,152
Asset retirement obligations		1,040,778			1,024,529
Derivative instrument valuation at market		254,568			212,263
Benefit obligations and other		145,586			128,247

Total deferred credits and other liabilities		3,182,075			3,059,549

Long-term debt		1,941,146			1,940,958
Common stock — authorized 5,000,000 shares of $0.01 par value, outstanding 1,000,000 shares		10			10
Premium on common stock		892,969			842,969
Retained earnings		981,942			965,880
Accumulated other comprehensive loss		(70	)		(4	)

Total common stockholder’s equity		1,874,851			1,808,855
Commitments and contingencies (see Note 4)

Total liabilities and equity	$	7,610,265		$	7,483,102

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

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


	Three Months Ended March 31,
	2004			2003
Operating revenues:
Electric utility	$	123,125		$	120,526
Natural gas utility		58,200			64,433
Other		163			68

Total operating revenues		181,488			185,027
Operating expenses:
Electric fuel and purchased power		53,900			55,463
Cost of natural gas sold and transported		45,762			50,656
Other operating and maintenance expenses		29,380			24,438
Depreciation and amortization		11,362			11,334
Taxes (other than income taxes)		4,316			4,227

Total operating expenses		144,720			146,118
Operating income		36,768			38,909
Other income (expense):
Interest income		146			161
Other nonoperating income		556			281
Nonoperating expense		(157	)		(102	)

Total other income (expense)		545			340
Interest charges — net of amounts capitalized; includes other financing costs of $303 and $224, respectively		5,280			5,731

Income before income taxes		32,033			33,518
Income taxes		12,819			13,664

Net income	$	19,214		$	19,854

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

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


	Three Months Ended March 31
	2004			2003
Operating activities:
Net income	$	19,214		$	19,854
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		11,800			11,591
Deferred income taxes		1,039			668
Amortization of investment tax credits		(197	)		(198	)
Allowance for equity funds used during construction		(468	)		(207	)
Undistributed equity in earnings of unconsolidated affiliates		7			(2	)
Change in accounts receivable		(5,849	)		(7,657	)
Change in inventories		5,745			3,950
Change in other current assets		10,142			4,483
Change in accounts payable		(7,212	)		1,968
Change in other current liabilities		17,845			16,532
Change in other assets		(2,885	)		(834	)
Change in other liabilities		(865	)		(675	)

Net cash provided by operating activities		48,316			49,473
Investing activities:
Capital/construction expenditures		(10,010	)		(9,155	)
Allowance for equity funds used during construction		468			207
Other investments – net		(183	)		(10	)

Net cash used in investing activities		(9,725	)		(8,958	)
Financing activities:
Short-term borrowings from affiliate – net		(23,710	)		(6,880	)
Dividends paid to parent		(12,563	)		(12,260	)

Net cash used in financing activities		(36,273	)		(19,140	)

Net increase in cash and cash equivalents		2,318			21,375
Net increase in cash and cash equivalents – adoption of FIN No. 46		683			—
Cash and cash equivalents at beginning of period		137			98

Cash and cash equivalents at end of period	$	3,138		$	21,473

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

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


	March 31,			Dec. 31,
	2004			2003
ASSETS
Current assets:
Cash and cash equivalents	$	3,138		$	137
Accounts receivable — net of allowance for bad debts: $1,109 and $1,212, respectively		45,478			42,603
Accounts receivable from affiliates		4,413			1,389
Accrued unbilled revenues		16,046			21,522
Materials and supplies inventories – at average cost		5,374			5,274
Fuel inventory – at average cost		7,977			4,962
Natural gas inventory — at average cost		719			9,578
Current deferred income taxes		5,343			3,430
Prepaid taxes		3,393			17,082
Prepayments and other		2,493			3,877

Total current assets		94,374			109,854

Property, plant and equipment, at cost:
Electric utility plant		1,205,382			1,189,122
Natural gas utility plant		139,536			138,767
Common and other plant		92,678			85,639
Construction work in progress		23,417			31,428

Total property, plant and equipment		1,461,013			1,444,956
Less accumulated depreciation		(556,538	)		(543,768	)

Net property, plant and equipment		904,475			901,188

Other assets:
Other investments		8,076			9,989
Regulatory assets		50,910			50,049
Prepaid pension asset		47,881			46,384
Other		7,648			7,407

Total other assets		114,515			113,829

Total assets	$	1,113,364		$	1,124,871

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	34		$	34
Notes payable to affiliate		—			23,710
Accounts payable		18,136			23,586
Accounts payable to affiliates		5,228			6,910
Accrued interest		9,257			4,266
Accrued payroll and benefits		4,956			5,431
Dividends payable to parent		12,291			12,563
Other		9,433			6,245

Total current liabilities		59,335			82,745

Deferred credits and other liabilities:
Deferred income taxes		161,938			158,972
Deferred investment tax credits		13,830			14,027
Regulatory liabilities		87,763			87,180
Customer advances for construction		16,763			18,015
Benefit obligations and other		26,193			25,371

Total deferred credits and other liabilities		306,487			303,565

Minority interest in subsidiaries		100			—
Long-term debt		315,349			313,410
Common stock — authorized 1,000,000 shares of $100 par value; outstanding 933,000 shares		93,300			93,300
Premium on common stock		63,457			63,457
Retained earnings		276,439			269,516
Accumulated other comprehensive income (loss)		(1,103	)		(1,122	)

Total common stockholder’s equity		432,093			425,151
Commitments and contingent liabilities (see Note 4)

Total liabilities and equity	$	1,113,364		$	1,124,871

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

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


	Three Months ended March 31,
	2004			2003
Operating revenues:
Electric utility	$	511,762		$	494,489
Electric trading margin		(453	)		(2,051	)
Natural gas utility		392,530			256,677
Steam and other		8,081			6,648

Total operating revenues		911,920			755,763
Operating expenses:
Electric fuel and purchased power		282,612			255,795
Cost of natural gas sold and transported		301,645			154,907
Cost of sales – steam and other		5,128			3,698
Other operating and maintenance expenses		128,959			114,768
Depreciation and amortization		52,421			58,643
Taxes (other than income taxes)		22,151			20,181

Total operating expenses		792,916			607,992

Operating income		119,004			147,771
Other income (expense):
Interest income		520			441
Other nonoperating income		4,013			1,562
Nonoperating expenses		(3,869	)		(3,204	)

Total other income (expense)		664			(1,201	)
Interest charges and financing costs:
Interest charges – net of amounts capitalized, includes other financing costs of $2,081 and $1,716, respectively		36,715			35,917
Distributions on redeemable preferred securities of subsidiary trust		—			3,686

Total interest charges and financing costs		36,715			39,603

Income before income taxes		82,953			106,967
Income taxes		27,787			36,880

Net income	$	55,166		$	70,087

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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


	Three Months Ended March 31,
	2004			2003
Operating activities:
Net income	$	55,166		$	70,087
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		53,240			61,509
Deferred income taxes		6,671			52,061
Amortization of investment tax credits		(1,408	)		(1,833	)
Allowance for equity funds used during construction		(3,502	)		(269	)
Change in accounts receivable		(20,704	)		(40,948	)
Change in unbilled revenue		32,983			83,157
Change in recoverable natural gas and electric costs		69,184			(93,100	)
Change in inventories		33,643			47,954
Change in other current assets		29,593			(8,054	)
Change in accounts payable		(127,292	)		(61,476	)
Change in other current liabilities		47,116			45,668
Change in other assets		(757	)		2,302
Change in other liabilities		23,067			7,863

Net cash provided by operating activities		197,000			164,921
Investing activities:
Capital/construction expenditures		(86,915	)		(78,694	)
Proceeds from disposition of property, plant and equipment		—			1,371
Allowance for equity funds used during construction		3,502			269
Other investments – net		4,688			(313	)

Net cash used in investing activities		(78,725	)		(77,367	)
Financing activities:
Short-term borrowings – net		(918	)		(88,537	)
Proceeds from issuance of long-term debt		—			247,277
Repayment of long-term debt, including reacquisition premiums		(145,520	)		(2,012	)
Capital contributions from parent		—			—
Dividends paid to parent		(59,598	)		(60,550	)

Net cash provided by (used in) financing activities		(206,036	)		96,178

Net increase (decrease) in cash and cash equivalents		(87,761	)		183,732
Cash and cash equivalents at beginning of period		125,101			25,924

Cash and cash equivalents at end of period	$	37,340		$	209,656

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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


	March 31,			Dec. 31,
	2004			2003
ASSETS
Current assets:
Cash and cash equivalents	$	37,340		$	125,101
Accounts receivable — net of allowance for bad debts: $13,140 and $12,852, respectively		255,143			260,023
Accounts receivable from affiliates		31,992			6,409
Accrued unbilled revenues		122,052			155,035
Recoverable purchased natural gas and electric energy costs		75,964			167,287
Materials and supplies inventories — at average cost		42,309			41,301
Fuel inventory — at average cost		27,163			25,041
Natural gas inventories – at average cost on March 31, 2004; replacement cost in excess of LIFO: $73,197 on Dec. 31, 2003 (see Note 1)		83,519			87,579
Derivative instruments valuation — at market		13,284			51,007
Prepayments and other		7,131			14,529

Total current assets		695,897			933,312

Property, plant and equipment, at cost:
Electric utility plant		5,783,394			5,635,907
Natural gas utility plant		1,601,611			1,556,740
Construction work in progress		690,083			653,806
Other		329,891			468,241

Total property, plant and equipment		8,404,979			8,314,694
Less accumulated depreciation		(2,770,665	)		(2,725,507	)

Net property, plant and equipment		5,634,314			5,589,187

Other assets:
Other investments		29,508			33,998
Regulatory assets		243,857			269,340
Derivative instruments valuation – at market		227,959			200,990
Deferred retail gas costs		—			10,619
Other		36,597			36,415

Total other assets		537,921			551,362

Total assets	$	6,868,132		$	7,073,861

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	2,141		$	147,131
Short-term debt		563			563
Note payable to affiliate		12,020			12,938
Accounts payable		268,956			369,974
Accounts payable to affiliates		32,883			59,132
Taxes accrued		118,819			77,679
Dividends payable to parent		61,867			59,598
Derivative instruments valuation — at market		43,555			55,845
Current deferred income tax		13,617			29,474
Accrued interest		58,087			47,974
Other		60,805			65,343

Total current liabilities		673,313			925,651

Deferred credits and other liabilities:
Deferred income taxes		657,516			638,182
Deferred investment tax credits		69,947			70,955
Regulatory liabilities		518,834			511,100
Customers advances for construction		200,624			191,800
Minimum pension liability		54,647			54,647
Derivative instruments valuation – at market		145,620			142,557
Benefit obligations and other		103,428			87,567

Total deferred credits and other liabilities		1,750,616			1,696,808

Long-term debt		2,311,189			2,311,434
Common stock – authorized 100 shares of $0.01 par value; outstanding 100 shares		—			—
Premium on common stock		1,797,780			1,797,780
Retained earnings		414,913			421,614
Accumulated comprehensive income (loss)		(79,679	)		(79,426	)

Total common stockholder’s equity		2,133,014			2,139,968

Commitments and contingencies (see Note 4)
Total liabilities and equity	$	6,868,132		$	7,073,861

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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


	Three Months Ended March 31,
	2004			2003
Operating revenues	$	306,557		$	244,597
Operating expenses:
Electric fuel and purchased power		189,319			140,188
Other operating and maintenance expenses		45,395			42,844
Depreciation and amortization		22,305			21,512
Taxes (other than income taxes)		13,545			11,730

Total operating expenses		270,564			216,274
Operating income		35,993			28,323
Other income (expense):
Interest income		205			1,138
Other nonoperating income		885			577
Nonoperating expense		(58	)		(35	)

Total other income (expense)		1,032			1,680
Interest charges and financing costs:
Interest charges — net of amounts capitalized, includes other financing costs of $1,756 and $1,639 respectively		12,788			11,732
Distributions on redeemable preferred securities of subsidiary trust		—			1,963

Total interest charges and financing costs		12,788			13,695

Income before income taxes		24,237			16,308
Income taxes		9,441			6,217

Net income	$	14,796		$	10,091

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

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


	Three Months Ended March 31
	2004			2003
Operating activities:
Net income	$	14,796		$	10,091
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		24,492			23,298
Deferred income taxes		8,536			4,491
Amortization of investment tax credits		(63	)		(63	)
Allowance for equity funds used during construction		(771	)		(575	)
Change in recoverable electric energy costs		(24,370	)		(1,415	)
Change in accounts receivable		11,445			(34,216	)
Change in unbilled revenues		8,355			8,945
Change in inventories		229			390
Change in other current assets		1,532			(1,143	)
Change in accounts payable		(1,853	)		31,218
Change in other current liabilities		(11,891	)		(3,873	)
Change in other noncurrent assets		(4,148	)		(3,581	)
Change in other noncurrent liabilities		1,752			1,493

Net cash provided by operating activities		28,041			35,060
Investing activities:
Capital/construction expenditures		(24,161	)		(20,690	)
Allowance for equity funds used during construction		771			575
Other investments – net		276			257

Net cash used in investing activities		(23,114	)		(19,858	)
Financing activities:
Proceeds from issuance of short-term debt		20,000			—
Dividends paid to parent		(23,987	)		(24,428	)

Net cash used in financing activities		(3,987	)		(24,428	)

Net increase (decrease) in cash and cash equivalents		940			(9,226	)
Cash and cash equivalents at beginning of period		9,869			60,700

Cash and cash equivalents at end of period	$	10,809		$	51,474

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

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


	March 31			Dec. 31
	2004			2003
ASSETS
Current assets:
Cash and cash equivalents	$	10,809		$	9,869
Accounts receivable — net of allowance for bad debts: $1,629 and $1,722, respectively		47,115			50,636
Accounts receivable from affiliates		8,763			16,687
Accrued unbilled revenues		54,898			63,253
Recoverable electric energy costs		73,796			49,426
Materials and supplies inventories — at average cost		14,178			14,405
Fuel inventory — at average cost		1,973			1,975
Derivative instruments valuation – at market		4,263			5,502
Prepayments and other		6,738			8,270

Total current assets		222,533			220,023

Property, plant and equipment, at cost:
Electric utility plant		3,178,614			3,146,315
Construction work in progress		83,511			92,239

Total property, plant and equipment		3,262,125			3,238,554
Less accumulated depreciation		(1,334,766	)		(1,314,272	)

Net property, plant and equipment		1,927,359			1,924,282

Other assets:
Other investments		13,378			13,654
Regulatory assets		105,896			108,587
Prepaid pension asset		124,237			121,580
Derivative instruments valuation – at market		58,945			50,960
Deferred charges and other		5,483			5,034

Total other assets		307,939			299,815

Total assets	$	2,457,831		$	2,444,120

LIABILITIES AND EQUITY
Current liabilities:
Short-term debt	$	20,000		$	—
Accounts payable		86,733			81,780
Accounts payable to affiliates		12,087			18,893
Taxes accrued		11,468			25,219
Accrued interest		15,600			10,645
Dividends payable to parent		23,547			23,987
Current deferred income taxes		19,229			13,088
Derivative instruments valuation — at market		31,669			29,957
Other		15,529			18,624

Total current liabilities		235,862			222,193

Deferred credits and other liabilities:
Deferred income taxes		416,869			415,039
Deferred investment tax credits		3,904			3,967
Regulatory liabilities		122,947			113,492
Derivative instruments valuation — at market		20,642			26,237
Benefit obligations and other		25,313			23,550

Total deferred credits and other liabilities		589,675			582,285

Long-term debt		825,225			825,147
Common stock – authorized 200 shares of $1.00 par value, outstanding 100 shares		—			—
Premium on common stock		414,118			414,118
Retained earnings		398,881			407,632
Accumulated other comprehensive loss		(5,930	)		(7,255	)

Total common stockholder’s equity		807,069			814,495
Commitments and contingencies (see Note 4)

Total liabilities and equity	$	2,457,831		$	2,444,120

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In the opinion of management, the accompanying unaudited consolidated and stand-alone financial statements contain all adjustments necessary to present fairly the financial position of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS (collectively, Utility Subsidiaries) as of March 31, 2004, and Dec. 31, 2003; the results of their operations for the three months ended March 31, 2004 and 2003; and their cash flows for the three months ended March 31, 2004 and 2003. Due to the seasonality of electric and natural gas sales of Xcel Energy’s Utility Subsidiaries, quarterly results are not necessarily an appropriate base from which to project annual results.

The accounting policies of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are set forth in Note 1 to their financial statements in their respective Annual Reports on Form 10-K for the year ended Dec. 31, 2003. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K’s.

1. Accounting Policies (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

FASB Interpretation No. 46 (FIN No. 46) — On Jan. 1, 2004, the Utility Subsidiaries adopted FIN No. 46, which requires an enterprise’s consolidated financial statements to include variable interest entities for which the enterprise is determined to be the primary beneficiary. Historically, consolidation has been required only for entities in which an enterprise has a majority voting or controlling interest. As a result, NSP-Wisconsin consolidated a portion of its affordable housing investments, which were previously accounted for under the equity method. The assets and liabilities consolidated were immaterial to NSP-Wisconsin. Xcel Energy evaluated various arrangements based on criteria in FIN No. 46. No other Utility Subsidiary arrangements were determined to be variable interests requiring disclosure or consolidation under FIN No. 46.

Change in Accounting Principle — Inventory — Effective Jan. 1, 2004, PSCo changed its method of accounting for the cost of stored natural gas for its local distribution operations from the last-in-first-out (LIFO) pricing method to the average cost pricing method. This change in accounting was approved by the Colorado Public Utilities Commission (CPUC) and was accounted for as a cumulative effect as required by the CPUC authorization. The average cost method has historically been used for pricing stored natural gas by both NSP-Minnesota and NSP-Wisconsin, as well as by PSCo for natural gas stored for use in its electric utility operations.

The cumulative effect of this change in accounting principle resulted in an increase to gas storage inventory and a corresponding decrease to the deferred gas cost accounts of approximately $36 million as of Jan. 1, 2004. Of this amount, $33 million related to current gas storage inventory and $3 million related to long-term gas storage inventory. As gas costs are 100 percent recoverable under PSCo’s gas cost adjustment mechanism, the cumulative effect of this change had no impact on net income or earnings per share. Prior period financial statements were not restated since the CPUC ordered this change effective Jan. 1, 2004. As ordered by the CPUC, the decrease in the cost of gas will reduce rates to retail gas customers in Colorado during 2004.

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

Market Based Rate Authority Rule Proposal – On April 14, 2004, the Federal Energy Regulatory Commission (FERC) initiated a new rulemaking on future market-based rates authorizations and issued interim requirements for FERC jurisdictional electric utilities that have been granted authority to make wholesale sales at market-based rates. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS currently have wholesale market-based rate authorization from the FERC. The FERC adopted a new interim method to assess generation market power and modified measures to mitigate market power where it is found. The assessments will be made of all initial market-based rate applications and triennial reviews on an interim basis. The Utility Subsidiaries’ triennial reviews are pending. An assessment will be made of whether the utility is a pivotal supplier based on a control area’s annual peak demand or it complies with market share requirements on a seasonal basis. If an applicant is determined to have generation market power, the applicant has the opportunity to propose its own mitigation plan or may implement default mitigation established by the FERC. The default mitigation limits prices for sales of power to cost-based rates within the areas where an applicant is found to have market power. Xcel Energy is reviewing the new requirements to determine what, if any, impact the new requirements will have on the wholesale market-based rate authority of the Utility Subsidiaries.

Department of Energy Blackout Report — On April 6, 2004, the U.S. Department of Energy issued its final report regarding the Aug. 14, 2003 electric blackout in the eastern United States, which did not affect the electric systems of the Utility Subsidiaries. The report recommends 47 specific changes to current statutes, rules or practices in order to improve the reliability of the infrastructure used to transmit electric power. The recommendations include the establishment of mandatory reliability standards and financial penalties for noncompliance. On April 14, 2004, FERC issued a policy statement requiring electric utilities, including the Utility Subsidiaries, to submit a report on vegetation management practices and indicating the FERC’s intent to make North American Electric Reliability Council (NERC) reliability standards mandatory. Xcel Energy is reviewing the final report and FERC policy statement. Implementation of the blackout report recommendations and the FERC policy statement could increase future transmission costs, but the extent of this effect cannot be determined at this time.

Midwest ISO Transmission and Energy Markets Tariff — On March 31, 2004, the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) regional transmission organization filed its proposed transmission and energy markets tariff, which would establish regional wholesale energy markets using locational marginal cost pricing and financial transmission rights. NSP-Minnesota and NSP-Wisconsin are Midwest ISO members, and their generation plants and transmission systems would operate subject to the tariff if it is approved by the FERC. The Midwest ISO proposed a Dec. 1, 2004 effective date. Comments regarding the tariff must be filed with the FERC by May 7, 2004. Implementation of a wholesale regional market using the locational marginal cost pricing and financial transmission rights is expected to provide a benefit to NSP-Minnesota and NSP-Wisconsin through a reduction in overall power costs. However, Xcel Energy opposes certain aspects of the tariff as proposed, and believes the Midwest ISO should implement the new market mechanisms only after it demonstrates that it will protect reliability.

Minnesota Service Quality Investigation - On Nov. 14, 2003, NSP-Minnesota submitted a proposed service quality plan and an update regarding certain service quality settlement agreement provisions already implemented by NSP-Minnesota. Among other provisions, the proposed service quality plan contains underperformance payments for the failure to meet certain reliability and customer service metrics. On March 10, 2004, the Minnesota Public Utilities Commission (MPUC) issued an order approving the settlement, but modifying it to include an annual independent audit of NSP-Minnesota’s service outage records and requiring additional under-performance payments for any future finding of inaccurate data by an independent auditor. Both state agencies and NSP-Minnesota have the option under the settlement to void in the event of a significant modification by the MPUC. On March 29, 2004, NSP-Minnesota submitted a Petition for Clarification of the MPUC’s March 10th order. Another party also submitted a Petition for Reconsideration on the same date. The MPUC has scheduled a hearing for May 13, 2004 to consider these petitions.

PSCo Least Cost Resource Plan – On April 30, 2004, PSCo filed its 2003 least-cost resource plan (LCP) with the CPUC. The LCP identifies the resources necessary to meet the PSCo’s load requirements for the period 2004 through 2013. PSCo has identified that it needs 3,600 megawatts of capacity to meet its customers’ requirements over this time period. Of this amount, PSCo believes that 2,000 megawatts will come from new resources, and that it will be able to enter into new contracts with existing suppliers whose contracts expire during the resource acquisition period for the remainder of its needs. As part of its resource plan PSCo is seeking waiver of certain LCP rules to allow it to build a new 750-megawatt coal-fired unit at its existing Comanche power plant site located in Pueblo, Colorado. PSCo plans to own 500 megawatts of this new facility. Two of the PSCo’s wholesale customers have options to participate in the ownership of the remaining 250 megawatts, and PSCo is in discussions with them regarding the plant’s development. In addition to requesting a certificate of public convenience and necessity for the new coal unit, PSCo is requesting in a separate application for CPUC authorization to construct and own the transmission facilities necessary to tie the new facility into the PSCo’s high voltage transmission network. PSCo is also filing a separate application for a specific regulatory plan to address the impacts of purchased capacity contracts on its capital structure and to expedite the recovery of the costs of financing the new power plant and related transmission.

PSCo Capacity Cost Adjustment - In October 2003, PSCo filed an application to recover incremental capacity costs through a purchased capacity cost adjustment (PCCA) rider. The PCCA is designed to recover purchased capacity payments to power suppliers that are not included in PSCo’s current base electric rates or other recovery mechanisms. Based on the current request, the capacity rider is expected to recover approximately $27 million in 2004, $44 million in 2005 and $38 million in 2006. In addition, PSCo has proposed to refund to its retail customers 100 percent of any electric earnings in excess of its authorized rate of return on equity, currently 10.75 percent, through 2006.

The CPUC staff and the Office of Consumer Counsel (OCC) have proposed that only resources approved by the CPUC as a part of a 1999 resource plan and the resources in base rates should factor into the PCCA calculation. Over the period 2004 through 2006, the CPUC staff and OCC position would reduce the PCCA revenue requested by PSCo by approximately one third. Hearings were held in April 2004. Based on the current schedule, PSCo expects a final decision with new rates in effect in June 2004, if the CPUC approves the PCCA.

3. Tax Matters — Corporate-Owned Life Insurance

PSCo’s wholly owned subsidiary PSR Investments, Inc. (PSRI) owns and manages permanent life insurance policies on some of PSCo employees, known as corporate-owned life insurance (COLI). At various times, borrowings have been made against the cash values of these COLI policies and deductions taken on the interest expense on these borrowings. The IRS has challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through 1997.

After consultation with tax counsel, Xcel Energy contends that the IRS determination is not supported by relevant tax law. Based upon this assessment, management continues to believe that the tax deduction of interest expense on the COLI policy loans is in full compliance with the law. Accordingly, PSRI has not recorded any provision for income tax or related interest or penalties that may be imposed by the IRS and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years.

In April 2004, Xcel Energy filed a lawsuit in U.S. District Court for the District of Minnesota against the IRS to establish its entitlement to deduct policy loan interest. The litigation could require several years to reach final resolution. Although the ultimate resolution of this matter is uncertain, it could have a material adverse effect on PSCo’s financial position and results of operations. Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding.

The total disallowance of interest expense deductions for the period of 1993 through 1997, as proposed by the IRS, is approximately $175 million. Additional interest expense deductions for the period 1998 through 2003 are estimated to total approximately $404 million. Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2003, would reduce earnings by an estimated $254 million after tax.

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 Xcel Energy’s financial position and results of operations.

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.

Other Contingencies - The circumstances set forth in Notes 13 and 14 to the financial statements in NSP-Minnesota’s, NSP-Wisconsin’s, PSCo’s and SPS’ Annual Reports on Form 10-K for the year ended Dec. 31, 2003, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference. Following are unresolved contingencies, which are material to the financial position of Xcel Energy’s Utility Subsidiaries:

• Tax Matters — See Note 3 to the consolidated financial statements for discussion of exposures regarding the tax deductibility of corporate-owned life insurance loan interest.

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

PSCo

At March 31, 2004, PSCo had approximately $0.6 million of short-term debt outstanding at a weighted average interest rate of 1.0 percent.

SPS

At March 31, 2004, SPS had $20 million of short-term debt outstanding at a weighted average interest rate of 1.955 percent.

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

Xcel Energy’s Utility Subsidiaries record all derivative instruments on the balance sheet at fair value unless exempted as a normal purchase or sale. Changes in non-exempt derivative instrument’s fair value are 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. Statement of Financial Accounting Standard (SFAS) No. 133, as amended, (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 hedges on Xcel Energy’s Utility Subsidiaries Other Comprehensive Income, included as a component of stockholders’ equity, are detailed in the following table:


	Three months ended
	March 31, 2004
	NSP-			NSP-
(Millions of dollars)	Minnesota			Wisconsin			PSCo			SPS
Balance at Jan. 1, 2004	$	0.0		$	(1.1	)	$	17.2		$	(7.2	)
After-tax net unrealized gains related to derivatives accounted for as hedges		0.4			0.0			0.0			1.1
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(0.5	)		0.0			(0.4	)		0.2

Accumulated other comprehensive income (loss) related to cash flow hedges — March 31, 2004	$	(0.1	)	$	(1.1	)	$	16.8		$	(5.9	)


	Three months ended
	March 31, 2003
	NSP-
(Millions of dollars)	Minnesota		PSCo		SPS
Balance at Jan. 1, 2003	$	0.0	$	1.0	$	(4.6	)
After-tax net unrealized gains related to derivatives accounted for as hedges		0.0		1.3		0.4
After-tax net realized losses on derivative transactions reclassified into earnings		0.0		0.4		0.0

Accumulated other comprehensive income (loss) related to cash flow hedges — March 31, 2003	$	0.0	$	2.7	$	(4.2	)

Cash Flow Hedges

NSP-Minnesota and PSCo enter into derivative instruments to manage variability of future cash flows from changes in commodity prices and interest rates. These derivative instruments are designated as cash flow hedges for accounting purposes, and the changes in the fair value of these instruments are recorded as a component of Other Comprehensive Income.

At March 31, 2004, NSP-Minnesota and PSCo had various commodity-related contracts designated as cash flow hedges extending through 2009. The fair value of these cash flow hedges is recorded in either Other Comprehensive Income or deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place. Amounts deferred in these accounts 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 March 31, 2004, NSP-Minnesota had net losses of $0.1 million accumulated in Other Comprehensive Income related to commodity cash flow hedge contracts 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 had no amount accumulated in Other Comprehensive Income related to commodity hedges to be recognized during the next 12 months.

NSP-Wisconsin, PSCo and SPS enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate 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. As of March 31, 2004, NSP-Wisconsin had net losses of $0.1 million, PSCo had net gains of $1.5 million and SPS had net losses of $1.0 million, respectively, accumulated in Other Comprehensive Income related to interest cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months.

Gains or losses on hedging transactions for the sales of electric energy are recorded as a component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs, and interest rate hedging transactions 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. There was no hedge ineffectiveness in the first quarter of 2004.

Derivatives Not Qualifying for Hedge Accounting

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

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 as normal and exempted from the accounting and reporting requirements of SFAS No. 133.

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

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

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

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

NSP-Minnesota


	Regulated		Regulated
	Electric		Natural		All		Consolidated
(Thousands of dollars)	Utility		Gas Utility		Other		Total
Three months ended March 31, 2004
Revenues from:
External customers	$	609,469	$	310,030	$	7,863	$	927,362
Internal customers		198		2,102		—		2,300

Total revenue		609,667		312,132		7,863		929,662
Segment net income	$	44,506	$	20,751	$	3,100	$	68,357
Three months ended March 31, 2003
Revenues from:
External customers	$	588,122	$	332,443	$	6,194	$	926,759
Internal customers		189		807		—		996

Total revenue		588,311		333,250		6,194		927,755
Segment net income	$	24,839	$	17,817	$	1,795	$	44,451

NSP-Wisconsin


	Regulated		Regulated
	Electric		Natural		All			Consolidated
(Thousands of dollars)	Utility		Gas Utility		Other			Total
Three months ended March 31, 2004
Revenues from:
External customers	$	123,086	$	56,869	$	163		$	180,118
Internal customers		39		1,331		—			1,370

Total revenue		123,125		58,200		163			181,488
Segment net income	$	16,101	$	3,408	$	(295	)	$	19,214
Three months ended March 31, 2003
Revenues from:
External customers	$	120,487	$	63,866	$	68		$	184,421
Internal customers		39		567		—			606

Total revenue		120,526		64,433		68			185,027
Segment net income	$	15,366	$	4,489	$	(1	)	$	19,854

PSCo


	Regulated		Regulated
	Electric		Natural		All		Consolidated
(Thousands of dollars)	Utility		Gas Utility		Other		Total
Three months ended March 31, 2004
Revenues from:
External customers	$	511,262	$	392,508	$	8,081	$	911,851
Internal customers		47		22		—		69

Total revenue		511,309		392,530		8,081		911,920
Segment net income	$	29,922	$	23,808	$	1,436	$	55,166
Three months ended March 31, 2003
Revenues from:
External customers	$	492,370	$	256,665	$	6,648	$	755,683
Internal customers		68		12		—		80

Total revenue		492,438		256,677		6,648		755,763
Segment net income	$	35,714	$	32,666	$	1,707	$	70,087

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 $306.6 million and $244.6 million for the three months ended March 31, 2004 and 2003, respectively.

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

NSP-Minnesota

The components of total comprehensive income are shown below:


	Three months ended
(Millions of dollars)	March 31
	2004			2003
Net income	$	68.4		$	44.5
Other comprehensive loss:
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges (see Note 6)		0.4			—
After-tax net realized (gains) losses on derivative transactions reclassified into earnings (see Note 6)		(0.5	)		—

Other comprehensive loss		(0.1	)		—

Comprehensive income	$	68.3		$	44.5

The accumulated comprehensive income in stockholder’s equity at March 31, 2004 and 2003, relates to valuation adjustments on NSP-Minnesota’s derivative financial instruments and hedging activities and the mark-to-market components of NSP-Minnesota’s marketable securities.

NSP-Wisconsin

The components of total comprehensive income are shown below:


	Three months ended
(Millions of dollars)	March 31
	2004		2003
Net income	$	19.2	$	19.9
Other comprehensive loss:
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges (see Note 6)		—		—

Other comprehensive loss		—		—

Comprehensive income	$	19.2	$	19.9

The accumulated comprehensive income in stockholder’s equity at March 31, 2004 and 2003, relates to valuation adjustments on NSP-Wisconsin’s derivative financial instruments and hedging activities 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
(Millions of dollars)	March 31
	2004			2003
Net income	$	55.2		$	70.1
Other comprehensive income:
After-tax net unrealized gains related to derivatives accounted for as hedges (see Note 6)		—			1.3
After-tax net realized losses (gains) on derivative transactions reclassified into earnings (see Note 6)		(0.4	)		0.4
Unrealized gain on marketable securities		0.1			—

Other comprehensive income (loss)		(0.3	)		1.7

Comprehensive income	$	54.9		$	71.8

The accumulated comprehensive income in stockholder’s equity at March 31, 2004 and 2003, relates to valuation adjustments on PSCo’s derivative financial instruments and hedging activities, 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
(Millions of dollars)	March 31
	2004		2003
Net income	$	14.8	$	10.1
Other comprehensive income (loss):
After-tax net unrealized gains related to derivatives accounted for as hedges (see Note 6)		1.1		0.4
After-tax net realized losses (gains) on derivative transactions reclassified into earnings (see Note 6)		0.2		—

Other comprehensive income		1.3		0.4

Comprehensive income	$	16.1	$	10.5

The accumulated comprehensive income in stockholder’s equity at March 31, 2004 and 2003, relates to valuation adjustments on SPS’ derivative financial instruments and hedging activities and unrealized losses related to its minimum pension liability.

9. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost


	Three months ended March 31,
(Thousands of dollars)	2004			2003			2004			2003
							Postretirement Health
Xcel Energy Inc.	Pension Benefits						Care Benefits
Service cost	$	16,350		$	18,943		$	1,625		$	1,328
Interest cost		38,175			45,190			12,900			11,747
Expected return on plan assets		(72,225	)		(82,287	)		(5,275	)		(5,624	)
Amortization of transition (asset) obligation )		(2	)		(500	)		3,700			3,432
Amortization of prior service cost (credit)		7,601			7,976			(550	)		(706	)
Amortization of net (gain) loss		(5,141	)		(11,382	)		5,550			2,878

Net periodic benefit cost (credit)		(15,242	)		(22,060	)	$	17,950		$	13,055
Costs not recognized due to the effects of regulation		10,177			12,084			—			—
Additional cost recognized due to the effects of regulation		—			—			973			973

Net benefit cost (credit) recognized for financial reporting	$	(5,065	)	$	(9,976	)	$	18,923		$	14,028

NSP-Minnesota
Net periodic benefit cost (credit)	$	(10,706	)	$	(12,671	)	$	4,980		$	3,400
Credits not recognized due to the effects of regulation		10,177			12,084			—			—

Net benefit cost (credit) recognized for financial reporting	$	(529	)	$	(587	)	$	4,980		$	3,400

NSP-Wisconsin
Net benefit cost (credit) recognized for financial reporting	$	(1,497	)	$	(1,889	)	$	769		$	475
PSCo
Net periodic benefit cost (credit)	$	2,456		$	125		$	9,838		$	8,050
Additional cost recognized due to the effects of regulation		—			—			973			973

Net benefit cost recognized for financial reporting	$	2,456		$	125		$	10,811		$	9,023

SPS
Net benefit cost (credit) recognized for financial reporting	$	(2,657	)	$	(3,313	)	$	1,520		$	1,250

Employer Contributions

In its Annual Report on Form 10-K for the year ending Dec. 31, 2003, PSCo disclosed that it expected to contribute $10 million to one of its pension plans in 2004. This contribution has not yet been made, but PSCo anticipates that it will be made before year end 2004.

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:

• Economic conditions, including their impact on capital expenditures and the ability of the Utility Subsidiaries of Xcel Energy to obtain financing on favorable terms, inflation rates and monetary fluctuations;

• Business conditions in the energy business;

• Demand for electricity in the nonregulated marketplace;

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

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

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

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

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

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

• Increased competition in the utility industry;

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

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

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

• Social attitudes regarding the utility and power industries;

• Risks associated with the California power market;

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

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

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

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

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

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, 2003. 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 March 31, 2004, there were no material changes to the financial market risks that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2003.

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

NSP-Minnesota’s Management’s Discussion and Analysis

Results of Operations

NSP-Minnesota’s net income was approximately $68.4 million for the first three months of 2004, compared with approximately $44.5 million for the first three months of 2003.

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 fuel and purchased power 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, which are associated with energy produced from NSP-Minnesota’s generation assets or energy purchases to serve native load. Electric commodity trading refers to the sales for resale activity of purchasing and reselling electric energy to the wholesale market. Short-term wholesale and electric commodity trading activities are considered part of the electric utility segment.

Margins from electric commodity trading activity conducted at NSP-Minnesota are partially redistributed to PSCo and SPS pursuant to the Joint Operating Agreement (JOA) approved by the FERC. Trading margins are reported net in the Consolidated Statements of Income. The following table details base electric utility, short-term wholesale and electric commodity trading revenue and margin:


	Base						Electric
	Electric			Short-term			Commodity			Consolidated
(Millions of dollars)	Utility			Wholesale			Trading			Total
Three months ended March 31, 2004
Electric utility revenue	$	555		$	53		$	—		$	608
Electric fuel and purchased power		(200	)		(16	)		—			(216	)
Electric trading revenue		—			—			42			42
Electric trading costs		—			—			(41	)		(41	)

Gross margin before operating expenses	$	355		$	37		$	1		$	393

Margin as a percentage of revenue		64.0	%		69.8	%		2.4	%		60.5	%
Three months ended March 31, 2003
Electric utility revenue	$	548		$	39		$	—		$	587
Electric fuel and purchased power		(193	)		(16	)		—			(209	)
Electric trading revenue		—			—			15			15
Electric trading costs		—			—			(14	)		(14	)

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

Margin as a percentage of revenue		64.8	%		59.0	%		6.7	%		63.0	%

The following summarizes the components of the changes in base electric revenue and base electric margin for the three months ended Mar. 31:

Base Electric Revenue


(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	3
Estimated impact of weather		(2	)
Fuel and purchased power cost recovery		3
Transmission and other		3

Total base electric revenue increase	$	7

Base Electric Margin


(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	3
Estimated impact of weather		(1	)
Transmission and other		(2	)

Total base electric margin increase (decrease)	$	—

Short-term wholesale and electric commodity trading sales margins increased approximately $14 million for the first quarter of 2004. First quarter of 2004 short-term wholesale results reflect the impact of high market prices and a pre-existing contract, which expired in the first quarter of 2004. The 2004 trading and short-term wholesale margins are expected to be slightly less than 2003 margins.

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 retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.


(Millions of dollars)	2004			2003
Natural gas utility revenue	$	312		$	333
Cost of natural gas sold and transported		(247	)		(269	)

Natural gas utility margin	$	65		$	64

Weather-adjusted natural gas sales declined for the first quarter, as customers reduced their usage to offset the impact of higher natural gas prices. The negative sales growth reduced both natural gas revenue and margin. The following summarizes the components of the changes in natural gas revenue and margin for the three months ended March 31:

Natural Gas Revenue


(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	(5	)
Estimated impact of weather on firm sales volume		(4	)
Purchased gas adjustment clause recovery		(21	)
Transportation and other		9

Total natural gas revenue decrease	$	(21	)

Natural Gas Margin


(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	(2	)
Estimated impact of weather on firm sales volume		(1	)
Transportation and other		4

Total natural gas margin increase	$	1

Non-Fuel Operating Expense and Other Costs — The following summarizes the components of the changes in other utility operating and maintenance expense for the three months ended March 31:


(Millions of dollars)	2004 vs 2003
Lower plant outage costs	$	(5	)
Lower performance-based compensation costs		(2	)
Lower nuclear costs		(2	)
Lower conservation improvement program costs		(1	)
Restricted stock unit accruals related to the 2003 grant		4
Higher medical and health care costs		2
Lower pension credits and 2003 401K match true-up		1
Other		(1	)

Total other utility operating and maintenance expense increase (decrease)	$	(4	)

Depreciation and amortization expense decreased by approximately $9.0 million, or 9.9 percent, for the first three months of 2004, compared with the first three months of 2003. During 2003, the Minnesota legislature authorized additional spent nuclear fuel storage at the Prairie Island nuclear plant. In December 2003, the MPUC extended the authorized useful lives of the two generating units at the Prairie Island nuclear plant until 2013 and 2014, respectively, retroactive to Jan. 1, 2003. Annual depreciation expense for 2004 is expected to be approximately $18 million lower than 2003, due to a change in the decommissioning accruals resulting from a related order.

Interest charges and financing costs decreased by approximately $3.1 million, or 8.5 percent, for the first three months of 2004, compared with the first three months of 2003. The decrease is due to the issuance of debt during 2003 to refinance higher coupon debt, including the redemption of the preferred securities of subsidiary trusts.

Income tax expense increased by approximately $9.4 million for the first three months of 2004, compared with the first three months of 2003. The increase is primarily due to higher pretax income in 2004. The effective tax rate for NSP-Minnesota was 33.9 percent in the first three months of 2004 and 36.5 percent in 2003. The decrease in the effective tax rate was primarily due to the increase in the allowance for funds used during construction (AFUDC) equity in 2004, which is excluded from taxable income.

NSP-WISCONSIN MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

NSP-Wisconsin’s net income was $19.2 million for the first three months of 2004, compared with $19.9 million for the first three months of 2003.

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 sold and changes in the unit costs of fuel and purchased power. The fuel and purchased power cost recovery mechanism of the Wisconsin jurisdiction may not allow for complete recovery of all expenses and, therefore, dramatic changes in costs or periods of extreme temperatures can impact earnings.


	Three months ended March 31,
(Millions of dollars)	2004			2003
Total electric utility revenue	$	123		$	121
Electric fuel and purchased power		(54	)		(56	)

Total electric utility margin	$	69		$	65

Margin as a percentage of revenue		56.1	%		53.7	%

The following summarizes the components of the changes in base electric revenue and base electric margin for the three months ended March 31:

Base Electric Revenue


(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	3
Estimated impact of weather		(1	)
Interchange Agreement billing with NSP-Minnesota		2
Other		(2	)

Total base electric revenue increase	$	2

Base Electric Margin


(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	2
Estimated impact of weather		(1	)
Fuel cost recovery		(1	)
Interchange Agreement billing with NSP-Minnesota		5
Other		(1	)

Total base electric margin increase	$	4

Natural Gas Utility Margins

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


	Three months ended March 31,
(Millions of dollars)	2004			2003
Natural gas revenue	$	58		$	64
Cost of natural gas purchased and transported		(46	)		(51	)

Natural gas margin	$	12		$	13

The following summarizes the components of the changes in natural gas revenue and margin for the three months ended March 31:

Natural Gas Revenue


(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	(1	)
Estimated impact of weather on firm sales volume		(1	)
Purchased gas adjustment clause recovery		(5	)
Transportation and other		1

Total natural gas revenue increase (decrease)	$	(6	)

Natural Gas Margin


(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	(1	)
Estimated impact of weather on firm sales volume		(1	)
Transportation and other		1

Total natural gas margin increase (decrease)	$	(1	)

Non-Fuel Operating Expense and Other Items

The following summarizes the components of the changes in other utility operating and maintenance expense for the three months ended March 31:


(Millions of dollars)	2004 vs 2003
Higher litigation costs	$	1
Lower pension credits		1
Restricted stock unit accruals related to the 2003 grant		1
Higher Interchange expense from NSP-Minnesota		1
Other		1

Total other utility operating and maintenance expense increase	$	5

Other income (expense) for the first three months of 2004 increased by approximately $0.2 million, compared with the first three months of 2003, largely due to higher AFUDC.

Interest expense decreased by approximately $0.5 million for the first three months of 2004 compared with the first three months of 2003, primarily due to the long-term debt refinancing in October 2003 at a lower coupon rate.

Income tax expense decreased by approximately $0.8 million in the first three months of 2004 compared with the first three months of 2003. The decrease was largely due to lower levels of pre-tax income.

PSCo’s MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

PSCo’s net income was approximately $55.2 million for the first three months of 2004, compared with approximately $70.1 million for the first three months of 2003.

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 fuel and purchased power costs do not significantly affect electric utility margin. In 2004, PSCo generally is expected to recover all prudently incurred electric fuel and purchased energy costs through an electric commodity adjustment clause.

PSCo has two distinct forms of wholesale sales: short-term wholesale and electric commodity trading. Short-term wholesale refers to electric sales for resale, which are associated with energy produced from PSCo’s generation assets or energy purchases to serve native load. Electric commodity trading refers to the sales for resale activity of purchasing and reselling electric energy to the wholesale market. Short-term wholesale and electric trading activities are considered part of the electric utility segment.

Margins from electric commodity trading activity conducted at PSCo are partially redistributed to NSP-Minnesota and SPS pursuant to the JOA. Trading margins are reported net in the Consolidated Statements of Income. The following table details base electric utility, short-term wholesale and electric commodity trading revenue and margin:


	Base						Electric
	Electric			Short-term			Commodity			Consolidated
(Millions of dollars)	Utility			Wholesale			Trading			Total
Three months ended March 31, 2004
Electric utility revenue	$	508		$	4		$	—		$	512
Electric fuel and purchased power		(279	)		(4	)		—			(283	)
Electric trading revenue		—			—			40			40
Electric trading costs		—			—			(40	)		(40	)

Gross margin before operating expenses	$	229		$	—		$	—		$	229

Margin as a percentage of revenue		45.1	%		0.0	%		0.0	%		41.5	%
Three months ended March 31, 2003
Electric utility revenue	$	474		$	20		$	—		$	494
Electric fuel and purchased power		(234	)		(22	)		—			(256	)
Electric trading revenue		—			—			43			43
Electric trading costs		—			—			(45	)		(45	)

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

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

The following summarizes the components of the changes in base electric revenue and base electric margin for the three months ended March 31:

Base Electric Revenue


(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	6
Estimated impact of weather		(1	)
Fuel cost recovery		33
Transmission and other		(4	)

Total base electric revenue increase	$	34

Base Electric Margin


(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	4
Estimated impact of weather		(1	)
Purchased capacity costs		(9	)
ECA first quarter incentive		3
Financial hedging costs		(4	)
2003 retail jurisdictional allocation adjustment		(5	)
Transmission and other		1

Total base electric margin decrease	$	(11	)

Natural Gas Utility Margins

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


	Three Months ended March 31,
(Millions of dollars)	2004			2003
Natural gas utility revenue	$	393		$	257
Cost of natural gas sold and transported		(302	)		(155	)

Natural gas utility margin	$	91		$	102

The following summarizes the components of the changes in natural gas revenue and margin for the three months ended March 31:

Natural Gas Revenue


(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	1
Estimated impact of weather on firm sales volume		(3	)
Purchased gas adjustment clause recovery		147
Rate changes – Colorado		(9	)

Total natural gas revenue increase	$	136

Natural Gas Margin


(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	1
Estimated impact of weather on firm sales volume		(3	)
Rate changes – Colorado		(9	)

Total natural gas margin decrease	$	(11	)

Non-Fuel Operating Expense and Other Items

PSCo’s Other Operating and Maintenance Expenses for the three months ending March 31, 2004 were approximately $14 million greater than for the three months ending March 31, 2003. The factors causing the increase are:


(Millions of dollars)	2004 vs 2003
Higher pension costs and 2003 401(k) match true-up	$	5
Restricted stock unit accruals related to the 2003 grant		3
Higher medical and health care costs		3
Timing of reliability and outside vendor costs		2
Higher information technology costs		1
Higher plant outage related costs		1
Lower performance-based compensation costs		(2	)
Other		1

Total	$	14

Depreciation and Amortization Expense decreased by approximately $6.2 million, or 10.6 percent, for the first three months of 2004 compared with the first three months of 2003. Effective July 1, 2003, the CPUC lengthened the depreciable lives of certain electric utility plant at PSCo as a part of the general Colorado rate case, which will reduce annual depreciation expense by $20 million. This action reduced 2003 depreciation expense by $10 million. Xcel Energy’s depreciation expense in 2004 will reflect the full year impact of this change.

Interest and financing costs decreased by approximately $2.9 million, or 7.3 percent, for the first three months of 2004 compared with the first three months of 2003. The decrease is due to the issuance of debt during 2003 to refinance higher coupon debt, including the redemption of the preferred securities of subsidiary trusts.

Income tax expense decreased by approximately $9.1 million in the first three months of 2004, compared with the first three months of 2003. The decrease was primarily due to lower pretax income levels.

SPS’ MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

SPS’ net income was approximately $14.8 million for the first three months of 2004, compared with approximately $10.1 million for the first three months of 2003.

Electric Utility Margins

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


	Base
	Electric			Short-term			Consolidated
(Millions of dollars)	Utility			Wholesale			Total
3 months ended 3/31/2004
Electric utility revenue	$	306		$	1		$	307
Electric fuel and purchased power		(188	)		(1	)		(189	)

Gross margin before operating expenses	$	118		$	—		$	118

Margin as a percentage of revenue		38.6	%		0.0	%		38.4	%
3 months ended 3/31/2003
Electric utility revenue	$	242		$	3		$	245
Electric fuel and purchased power		(138	)		(2	)		(140	)

Gross margin before operating expenses	$	104		$	1		$	105

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

Base Electric Revenue


(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	4
Capacity sales		3
Fuel cost recovery		55
Transmission and other		2

Total base electric revenue increase (decrease)	$	64

Base Electric Margin


(Millions of dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	3
Capacity sales		3
Fuel cost settlement		5
Wheeling costs		2
Transmission and other		1

Total base electric margin increase	$	14

Non-Fuel Operating Expense and Other Costs

The following summarizes the components of the changes in other utility operating and maintenance expense for the three months ended March 31:


(Millions of dollars)	2004 vs 2003
Higher plant outage costs	$	3
Higher medical and health care costs		2
Restricted stock unit accruals related to the 2003 grant		2
Unfavorable inventory adjustment in 2003		(3	)
Lower performance-based compensation costs		(1	)

Total other utility operating and maintenance expense increase	$	3

Taxes (other than income taxes) increased by approximately $1.8 million, or 15.5 percent, for the first three months of 2004, compared with the first three months of 2003. The increase is primarily due to higher franchise taxes and gross receipts taxes in Texas.

Other income (expense) decreased by approximately $0.6 million, or 38.6 percent, for the first three months of 2004, compared with the first three months of 2003. The decrease is primarily due to lower cash levels that resulted in lower interest income in 2004.

Income taxes increased by approximately $3.2 million for the first three months of 2004, compared with the first three months of 2003. The increase is primarily due to higher levels of pre-tax income.

Item 4. CONTROLS AND PROCEDURES

Xcel Energy’s Utility Subsidiaries maintain a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. 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 Subsidiary management, including their chief executive officers (CEO) and chief financial officers (CFO), of the effectiveness of their disclosure controls and procedures, the CEOs and CFOs have concluded that the Utility Subsidiary disclosure controls and procedures are effective.

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

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 2 and 4 of the Financial Statements in this Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 of NSP-Minnesota’s, NSP-Wisconsin’s, PSCo’s and SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2003 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.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

The following Exhibits are filed with this report:


31.01		Principal Executive Officer’s and Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 – NSP-Minnesota.

31.02		Principal Executive Officer’s and Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 – NSP-Wisconsin.

31.03		Principal Executive Officer’s and Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 – PSCo.

31.04		Principal Executive Officer’s and Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted 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 of 1995.

(b) Reports on Form 8-K

The following reports on Form 8-K were filed either during the three months ended March 31, 2004, or between March 31, 2004, and the date of this report:

None.

	•		Economic conditions, including their impact on capital expenditures and the ability of the Utility Subsidiaries of Xcel Energy to obtain financing on favorable terms, inflation rates and monetary fluctuations;

	•		Business conditions in the energy business;

	•		Demand for electricity in the nonregulated marketplace;

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

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

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

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

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

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

	•		Increased competition in the utility industry;

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

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

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

	•		Social attitudes regarding the utility and power industries;

	•		Risks associated with the California power market;

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

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

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

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

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


		Northern States Power Co. (a Minnesota corporation)
		(Registrant)

		/s/ TERESA S. MADDEN

		Teresa S. Madden
		Vice President and Controller

		/s/ BENJAMIN G.S. FOWKE

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


		Northern States Power Co. (a Wisconsin corporation)
		(Registrant)

		/s/ TERESA S MADDEN

		Teresa S. Madden
		Vice President and Controller

		/s/ BENJAMIN G.S. FOWKE III

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