NORTHERN STATES POWER CO - 10-Q Quarterly Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

	For the quarterly period ended Sept. 30, 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

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

001-03140	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 ý 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 ý

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

PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(Thousands of Dollars)

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2004			2003			2004			2003
Operating revenues:
Electric utility	$	738,758		$	750,318		$	1,943,457		$	1,908,867
Electric trading margin	509			6,492			1,395			9,893
Natural gas utility	61,230			58,366			467,516			480,494
Other	262			(789		)	14,994			10,149
Total operating revenues	800,759			814,387			2,427,362			2,409,403

Operating expenses:
Electric fuel and purchased power	296,692			268,420			725,448			682,154
Cost of natural gas sold and transported	39,179			36,238			356,333			367,700
Other operating and maintenance expenses	208,554			213,433			625,363			637,022
Depreciation and amortization	82,866			94,174			247,365			284,845
Taxes (other than income taxes)	46,286			46,897			135,335			134,073
Total operating expenses	673,577			659,162			2,089,844			2,105,794

Operating income	127,182			155,225			337,518			303,609

Other income (expense):
Interest income	1,424			1,428			4,663			4,821
Other nonoperating income	5,421			4,025			13,599			12,179
Nonoperating expense	(1,278		)	(1,898		)	(4,177		)	(5,067		)
Total other income (expense)	5,567			3,555			14,085			11,933

Interest charges and financing costs:
Interest charges — net of amounts capitalized, includes other financing costs of $1,871, $2,440, $6,368 and $6,420, respectively	31,253			31,028			96,596			92,923
Distributions on redeemable preferred securities of subsidiary trust	—			1,313			—			9,188
Total interest charges and financing costs	31,253			32,341			96,596			102,111
Income before income taxes	101,496			126,439			255,007			213,431

Income taxes	33,061			46,029			83,952			68,929
Net income	$	68,435		$	80,410		$	171,055		$	144,502

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

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

	Nine Months Ended Sept. 30,
	2004			2003
Operating activities:
Net income	$	171,055		$	144,502
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	256,804			293,633
Nuclear fuel amortization	33,691			32,982
Deferred income taxes	29,968			(4,615		)
Amortization of investment tax credits	(5,362		)	(5,942		)
Allowance for equity funds used during construction	(13,950		)	(9,464		)
Change in accounts receivable	42,967			(17,531		)
Change in accounts receivable from affiliates	27,057			714
Change in inventories	(15,925		)	(14,454		)
Change in other current assets	13,044			(18,981		)
Change in accounts payable	(4,523		)	(61,354		)
Change in other current liabilities	4,159			(89,715		)
Change in other noncurrent assets	(8,511		)	(50,569		)
Change in other noncurrent liabilities	20,531			46,152
Net cash provided by operating activities	551,005			245,358

Investing activities:
Capital/construction expenditures	(436,444		)	(218,068		)
Allowance for equity funds used during construction	13,950			9,464
Investments in external decommissioning fund	(60,435		)	(42,669		)
Restricted cash	—			23,000
Other investments — net	(1,866		)	(1,509		)
Net cash used in investing activities	(484,795		)	(229,782		)

Financing activities:
Short-term borrowings — net	(58,000		)	(69		)
Proceeds from issuance of long-term debt	—			372,459
Repayment of long-term debt, including reacquisition premiums	(57		)	(408,484		)
Capital contribution from parent	96,117			4,114
Dividends paid to parent	(159,744		)	(159,181		)
Net cash used in financing activities	(121,684		)	(191,161		)

Net decrease in cash and cash equivalents	(55,474		)	(175,585		)
Cash and cash equivalents at beginning of period	82,015			310,338
Cash and cash equivalents at end of period	$	26,541		$	134,753

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	111,359		$	109,396
Cash paid for income taxes (net of refunds received)	$	30,735		$	172,949

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

NSP-MINNESOTA

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

	Sept. 30, 2004			Dec. 31, 2003
ASSETS
Current assets:
Cash and cash equivalents	$	26,541		$	82,015
Accounts receivable — net of allowance for bad debts: $7,940 and $7,581, respectively	235,179			278,146
Accounts receivable from affiliates	45,469			72,526
Accrued unbilled revenues	93,486			125,872
Materials and supplies inventories — at average cost	99,844			100,297
Fuel inventory — at average cost	30,217			27,727
Natural gas inventory — at average cost	57,367			43,479
Income tax receivable	—			11,249
Derivative instrument valuation — at market	35,468			34,859
Prepayments and other	40,395			21,818
Total current assets	663,966			797,988
Property, plant and equipment, at cost:
Electric utility plant	7,439,921			7,268,609
Natural gas utility plant	774,445			746,835
Construction work in progress	488,509			328,880
Other	424,410			400,448
Total property, plant and equipment	9,127,285			8,744,772
Less accumulated depreciation	(4,187,079		)	(3,991,875		)
Nuclear fuel — net of accumulated amortization: $1,135,623 and $1,101,932, respectively	71,898			80,289
Net property, plant and equipment	5,012,104			4,833,186
Other assets:
Nuclear decommissioning fund investments	870,289			779,382
Other investments	25,675			25,055
Regulatory assets	516,547			492,491
Prepaid pension asset	346,873			317,956
Derivative instrument valuation — at market	335,601			177,581
Other	49,017			59,463
Total other assets	2,144,002			1,851,928
Total assets	$	7,820,072		$	7,483,102
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	11,997		$	4,502
Short-term debt	—			58,000
Accounts payable	224,852			250,628
Accounts payable to affiliates	54,137			32,884
Taxes accrued	137,122			116,862
Accrued interest	24,949			44,485
Dividends payable to parent	53,289			53,852
Derivative instrument valuation — at market	163,005			67,664
Other	53,528			44,863
Total current liabilities	722,879			673,740
Deferred credits and other liabilities:
Deferred income taxes	772,756			738,677
Deferred investment tax credits	61,010			66,681
Regulatory liabilities	945,770			889,152
Asset retirement obligations	1,074,054			1,024,529
Derivative instrument valuation — at market	247,476			212,263
Benefit obligations and other	145,153			128,247
Total deferred credits and other liabilities	3,246,219			3,059,549
Long-term debt	1,934,127			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	939,086			842,969
Retained earnings	977,755			965,880
Accumulated other comprehensive loss	(4		)	(4		)
Total common stockholder’s equity	1,916,847			1,808,855
Commitments and contingencies (see Note 4)
Total liabilities and equity	$	7,820,072		$	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 Sept. 30,						Nine Months Ended Sept. 30,
	2004			2003			2004			2003
Operating revenues:
Electric utility	$	122,642		$	129,207		$	354,925		$	357,781
Natural gas utility	12,691			9,305			88,337			90,025
Other	162			81			479			157
Total operating revenues	135,495			138,593			443,741			447,963

Operating expenses:
Electric fuel and purchased power	48,706			62,945			157,842			175,127
Cost of natural gas sold and transported	8,673			5,940			66,845			67,574
Other operating and maintenance expenses	28,475			27,685			86,799			79,755
Depreciation and amortization	11,718			11,766			34,651			34,903
Taxes (other than income taxes)	4,158			4,119			12,635			12,378
Total operating expenses	101,730			112,455			358,772			369,737

Operating income	33,765			26,138			84,969			78,226

Other income (expense):
Interest income	134			9			496			306
Other nonoperating income	68			320			1,267			989
Nonoperating expense	(82		)	(123		)	(398		)	(329		)
Total other income (expense)	120			206			1,365			966

Interest charges — net of amounts capitalized, includes other financing costs of $308, $223, $916 and $671, respectively	5,230			5,661			15,640			17,085
Income before income taxes	28,655			20,683			70,694			62,107

Income taxes	11,003			8,404			27,418			25,127
Net income	$	17,652		$	12,279		$	43,276		$	36,980

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

NSP-WISCONSIN

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

	Nine Months Ended Sept. 30,
	2004			2003
Operating activities:
Net income	$	43,276		$	36,980
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	36,098			35,685
Deferred income taxes	5,479			5,481
Amortization of investment tax credits	(591		)	(594		)
Allowance for equity funds used during construction	(1,156		)	(932		)
Undistributed equity in earnings of unconsolidated affiliates	(21		)	92
Change in accounts receivable	(1,101		)	15,621
Change in inventories	(3,933		)	(5,875		)
Change in other current assets	11,645			7,415
Change in accounts payable	(12,047		)	(7,028		)
Change in other current liabilities	11,694			3,221
Change in other noncurrent assets	(4,860		)	(5,743		)
Change in other noncurrent liabilities	1,941			(1,446		)
Net cash provided by operating activities	86,424			82,877

Investing activities:
Capital/construction expenditures	(36,696		)	(40,261		)
Allowance for equity funds used during construction	1,156			932
Other investments — net	(423		)	37
Net cash used in investing activities	(35,963		)	(39,292		)

Financing activities:
Short-term borrowings — net	(13,980		)	(6,880		)
Capital contributions from parent	687			692
Dividends paid to parent	(37,207		)	(37,397		)
Net cash used in financing activities	(50,500		)	(43,585		)

Net (decrease) increase in cash and cash equivalents	(39		)	—
Net increase in cash and cash equivalents — adoption of FIN No. 46	119			—
Cash and cash equivalents at beginning of period	137			98
Cash and cash equivalents at end of period	$	217		$	98

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	9,703		$	14,796
Cash paid for income taxes (net of refunds received)	$	13,384		$	18,573

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

NSP-WISCONSIN

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

	Sept. 30, 2004			Dec. 31, 2003
ASSETS
Current assets:
Cash and cash equivalents	$	217		$	137
Accounts receivable — net of allowance for bad debts: $1,635 and $1,212, respectively	32,908			42,603
Accounts receivable from affiliates	12,236			1,389
Accrued unbilled revenues	13,123			21,522
Materials and supplies inventories — at average cost	5,346			5,274
Fuel inventory – at average cost	6,925			4,962
Natural gas inventory — at average cost	11,476			9,578
Current deferred income taxes	4,092			3,430
Prepaid taxes (other than income taxes)	10,399			17,082
Derivative instrument valuations – at market	3,255			307
Prepayments and other	4,087			3,570
Total current assets	104,064			109,854
Property, plant and equipment, at cost:
Electric utility plant	1,219,161			1,189,122
Natural gas utility plant	144,174			138,767
Common and other plant	95,711			85,639
Construction work in progress	22,569			31,428
Total property, plant and equipment	1,481,615			1,444,956
Less accumulated depreciation	(571,186		)	(543,768		)
Net property, plant and equipment	910,429			901,188
Other assets:
Other investments	8,334			9,989
Regulatory assets	49,079			50,049
Prepaid pension asset	50,800			46,384
Other	7,949			7,407
Total other assets	116,162			113,829
Total assets	$	1,130,655		$	1,124,871

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	34		$	34
Notes payable to affiliate	9,730			23,710
Accounts payable	14,308			23,586
Accounts payable to affiliates	4,203			6,910
Taxes accrued	6,826			—
Accrued interest	9,287			4,266
Accrued payroll and benefits	5,944			5,431
Dividends payable to parent	12,205			12,563
Other	6,319			6,245
Total current liabilities	68,856			82,745
Deferred credits and other liabilities:
Deferred income taxes	163,969			158,972
Deferred investment tax credits	13,435			14,027
Regulatory liabilities	91,623			87,180
Customer advances for construction	17,906			18,015
Benefit obligations and other	26,980			25,371
Total deferred credits and other liabilities	313,913			303,565
Minority interest in subsidiaries	100			—
Long-term debt	315,463			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	64,144			63,457
Retained earnings	275,944			269,516
Accumulated other comprehensive loss	(1,065		)	(1,122		)
Total common stockholder’s equity	432,323			425,151
Commitments and contingent liabilities (see Note 4)
Total liabilities and equity	$	1,130,655		$	1,124,871

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

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(Thousands of Dollars)

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2004			2003			2004			2003
Operating revenues:
Electric utility	$	612,034		$	587,429		$	1,629,194		$	1,574,652
Electric trading margin	622			645			(157		)	657
Natural gas utility	117,198			111,160			671,510			529,498
Steam and other	3,690			4,354			18,149			15,723
Total operating revenues	733,544			703,588			2,318,696			2,120,530

Operating expenses:
Electric fuel and purchased power	357,623			325,370			934,688			856,087
Cost of natural gas sold and transported	63,334			58,620			468,600			310,810
Cost of sales – steam and other	2,606			2,519			11,125			8,946
Other operating and maintenance expenses	111,354			118,069			369,876			348,809
Depreciation and amortization	57,072			55,194			164,211			175,841
Taxes (other than income taxes)	21,563			21,221			65,235			64,257
Total operating expenses	613,552			580,993			2,013,735			1,764,750

Operating income	119,992			122,595			304,961			355,780

Other income (expense):
Interest income	239			473			1,023			2,484
Other nonoperating income	4,597			2,839			12,905			8,722
Nonoperating expenses	(4,516		)	(3,935		)	(13,357		)	(11,352		)
Total other income (expense)	320			(623		)	571			(146		)

Interest charges and financing costs:
Interest charges – net of amounts capitalized, includes other financing costs of $1,664, $2,025, $5,677 and $5,940, respectively	35,994			36,998			108,845			113,594
Distributions on redeemable preferred securities of subsidiary trust	—			—			—			7,372
Total interest charges and financing costs	35,994			36,998			108,845			120,966
Income before income taxes	84,318			84,974			196,687			234,668

Income taxes	25,213			27,491			54,484			73,444
Net income	$	59,105		$	57,483		$	142,203		$	161,224

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

	Nine Months Ended Sept. 30,
	2004			2003
Operating activities:
Net income	$	142,203		$	161,224
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	172,228			181,674
Deferred income taxes	28,450			86,147
Amortization of investment tax credits	(4,224		)	(5,499		)
Allowance for equity funds used during construction	(7,778		)	(5,364		)
Change in accounts receivable	(27,690		)	(17,124		)
Change in unbilled revenue	(40,263		)	74,166
Change in recoverable natural gas and electric costs	93,503			(52,055		)
Change in inventories	(32,652		)	4,282
Change in other current assets	(11,401		)	(65,092		)
Change in accounts payable	(25,109		)	(33,833		)
Change in other current liabilities	16,930			14,434
Change in other noncurrent assets	(13,474		)	35,786
Change in other noncurrent liabilities	10,995			30,213
Net cash provided by operating activities	301,718			408,959

Investing activities:
Capital/construction expenditures	(301,867		)	(301,769		)
Proceeds from sale of property	7,781			4,636
Allowance for equity funds used during construction	7,778			5,364
Other investments – net	(90		)	(24,039		)
Net cash used in investing activities	(286,398		)	(315,808		)

Financing activities:
Short-term borrowings – net	24,749			(90,070		)
Proceeds from issuance of long-term debt	—			816,221
Repayment of long-term debt, including reacquisition premiums	(146,586		)	(597,343		)
Capital contributions from parent	165,045			1,490
Dividends paid to parent	(182,443		)	(178,665		)
Net cash used in financing activities	(139,235		)	(48,367		)

Net increase (decrease) in cash and cash equivalents	(123,915		)	44,784
Cash and cash equivalents at beginning of period	125,101			25,924
Cash and cash equivalents at end of period	$	1,186		$	70,708

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	97,492		$	108,978
Cash paid for income taxes (net of refunds received)	$	11,159		$	(7,674	)

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

	Sept. 30, 2004			Dec. 31, 2003
ASSETS
Current assets:
Cash and cash equivalents	$	1,186		$	125,101
Accounts receivable — net of allowance for bad debts: $14,023 and $12,852, respectively	264,599			260,023
Accounts receivable from affiliates	17,347			6,409
Accrued unbilled revenues	195,298			155,035
Recoverable purchased natural gas and electric energy costs	51,645			167,287
Materials and supplies inventories — at average cost	46,464			41,301
Fuel inventory — at average cost	27,327			25,041
Natural gas inventories — at average cost on Sept. 30, 2004; replacement cost in excess of LIFO: $73,197 on Dec. 31, 2003 (see Note 1)	145,494			87,579
Derivative instruments valuation — at market	61,500			51,007
Deferred income taxes	14,084			—
Prepayments and other	14,493			14,529
Total current assets	839,437			933,312
Property, plant and equipment, at cost:
Electric utility plant	5,991,672			5,635,907
Natural gas utility plant	1,662,032			1,556,740
Construction work in progress	253,726			468,241
Other	764,221			653,806
Total property, plant and equipment	8,671,651			8,314,694
Less accumulated depreciation	(2,844,339		)	(2,725,507		)
Net property, plant and equipment	5,827,312			5,589,187
Other assets:
Other investments	34,332			33,998
Regulatory assets	224,115			269,340
Derivative instruments valuation — at market	248,890			200,990
Deferred retail gas costs	—			10,619
Other	41,266			36,415
Total other assets	548,603			551,362
Total assets	$	7,215,352		$	7,073,861

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	2,105		$	147,131
Short-term debt	27,000			563
Note payable to affiliate	11,250			12,938
Accounts payable	373,234			369,974
Accounts payable to affiliates	30,940			59,132
Taxes accrued	76,985			77,679
Dividends payable to parent	61,463			59,598
Derivative instruments valuation — at market	58,534			55,845
Current deferred income tax	—			29,474
Accrued interest	55,206			47,974
Other	74,535			65,343
Total current liabilities	771,252			925,651
Deferred credits and other liabilities:
Deferred income taxes	663,822			638,182
Deferred investment tax credits	67,931			70,955
Regulatory liabilities	565,963			511,100
Customers advances for construction	272,833			191,800
Minimum pension liability	15,460			54,647
Derivative instruments valuation — at market	149,328			142,557
Benefit obligations and other	136,785			87,567
Total deferred credits and other liabilities	1,872,122			1,696,808
Long-term debt	2,310,615			2,311,434
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares	—			—
Premium on common stock	1,962,825			1,797,780
Retained earnings	379,508			421,614
Accumulated comprehensive loss	(80,970		)	(79,426		)
Total common stockholder’s equity	2,261,363			2,139,968
Commitments and contingencies (see Note 4)
Total liabilities and equity	$	7,215,352		$	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 Sept. 30,					Nine Months Ended Sept. 30,
	2004		2003			2004			2003
Operating revenues	$	390,077	$	380,463		$	1,044,233		$	909,402

Operating expenses:
Electric fuel and purchased power	252,904		232,087			669,552			542,691
Other operating and maintenance expenses	41,694		41,411			129,585			122,441
Depreciation and amortization	23,098		22,210			68,148			65,519
Taxes (other than income taxes)	13,328		11,791			38,163			35,078
Total operating expenses	331,024		307,499			905,448			765,729

Operating income	59,053		72,964			138,785			143,673

Other income (expense):
Interest income	360		361			1,163			1,284
Other nonoperating income	75		1,483			1,633			3,178
Nonoperating expense	15		(72		)	(200		)	(143		)
Total other income (expense)	450		1,772			2,596			4,319

Interest charges and financing costs:
Interest charges — net of amounts capitalized, includes other financing costs of $1,555, $1,772, $4,941 and $5,201, respectively	12,770		11,548			38,442			33,954
Distributions on redeemable preferred securities of subsidiary trust	—		1,308			—			5,233
Total interest charges and financing costs	12,770		12,856			38,442			39,187
Income before income taxes	46,733		61,880			102,939			108,805

Income taxes	17,979		23,756			39,316			41,693
Net income	$	28,754	$	38,124		$	63,623		$	67,112

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

	Nine Months Ended Sept. 30,
	2004			2003
Operating activities:
Net income	$	63,623		$	67,112
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	74,601			71,986
Deferred income taxes	23,058			669
Amortization of investment tax credits	(188		)	(188		)
Allowance for equity funds used during construction	(1,199		)	(2,380		)
Change in recoverable electric energy costs	(40,793		)	(43,864		)
Change in accounts receivable	(23,014		)	(5,862		)
Change in unbilled revenues	4,111			(16,552		)
Change in inventories	482			609
Change in other current assets	(1,171		)	(2,897		)
Change in accounts payable	211			11,131
Change in other current liabilities	14,236			13,916
Change in other noncurrent assets	(11,913		)	(15,015		)
Change in other noncurrent liabilities	3,137			6,104
Net cash provided by operating activities	105,181			84,769

Investing activities:
Capital/construction expenditures	(84,855		)	(77,876		)
Allowance for equity funds used during construction	1,199			2,380
Other investments — net	3,666			(1,232		)
Net cash used in investing activities	(79,990		)	(76,728		)

Financing activities:
Short-term borrowings — net	45,000			17,000
Capital contributions from parent	1,032			1,391
Dividends paid to parent	(70,606		)	(73,319		)
Net cash used in financing activities	(24,574		)	(54,928		)

Net increase (decrease) in cash and cash equivalents	617			(46,887		)
Cash and cash equivalents at beginning of period	9,869			60,700
Cash and cash equivalents at end of period	$	10,486		$	13,813

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	29,437		$	23,555
Cash paid for income taxes (net of refunds received)	$	6,966		$	22,153

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

	Sept. 30, 2004			Dec. 31, 2003
ASSETS
Current assets:
Cash and cash equivalents	$	10,486		$	9,869
Accounts receivable — net of allowance for bad debts: $1,782 and $1,722, respectively	82,689			50,636
Accounts receivable from affiliates	7,648			16,687
Accrued unbilled revenues	59,142			63,253
Recoverable electric energy costs	90,219			49,426
Materials and supplies inventories — at average cost	14,003			14,405
Fuel inventory — at average cost	1,895			1,975
Derivative instruments valuation — at market	1,480			5,502
Prepayments and other	9,441			8,270
Total current assets	277,003			220,023
Property, plant and equipment, at cost:
Electric utility plant	3,245,657			3,146,315
Construction work in progress	74,572			92,239
Total property, plant and equipment	3,320,229			3,238,554
Less accumulated depreciation	(1,374,642		)	(1,314,272		)
Net property, plant and equipment	1,945,587			1,924,282
Other assets:
Other investments	9,988			13,654
Regulatory assets	155,037			108,587
Prepaid pension asset	129,963			121,580
Derivative instruments valuation — at market	52,835			50,960
Deferred charges and other	5,169			5,034
Total other assets	352,992			299,815
Total assets	$	2,575,582		$	2,444,120

LIABILITIES AND EQUITY
Current liabilities:
Short-term debt	$	45,000		$	—
Accounts payable	91,524			81,780
Accounts payable to affiliates	9,360			18,893
Taxes accrued	36,247			25,219
Accrued interest	15,140			10,645
Dividends payable to parent	23,043			23,987
Current deferred income taxes	15,496			13,088
Derivative instruments valuation — at market	7,543			29,957
Other	17,338			18,624
Total current liabilities	260,691			222,193
Deferred credits and other liabilities:
Deferred income taxes	432,698			415,039
Deferred investment tax credits	3,779			3,967
Regulatory liabilities	107,373			113,492
Derivative instruments valuation — at market	107,808			26,237
Benefit obligations and other	26,687			23,550
Total deferred credits and other liabilities	678,345			582,285
Long-term debt	825,382			825,147
Common stock — authorized 200 shares of $1.00 par value, outstanding 100 shares	—			—
Premium on common stock	415,150			414,118
Retained earnings	401,592			407,632
Accumulated other comprehensive loss	(5,578		)	(7,255		)
Total common stockholder’s equity	811,164			814,495
Commitments and contingencies (see Note 4)
Total liabilities and equity	$	2,575,582		$	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 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) and their respective subsidiaries (collectively, Utility Subsidiaries) as of Sept. 30, 2004, and Dec. 31, 2003; the results of their operations for the three and nine months ended Sept. 30, 2004 and 2003; and their cash flows for the nine months ended Sept. 30, 2004 and 2003. Due to the seasonality of electric and natural gas sales of the Utility Subsidiaries, such interim results are not necessarily an appropriate base from which to project annual results.

The accounting policies of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are set forth in Note 1 to their 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 Annual Reports on Form 10-K.

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 as revised, 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. The Utility Subsidiaries evaluated various arrangements based on criteria in FIN No. 46. No other arrangements were determined to be material 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 in accordance with 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 natural gas storage inventory and a corresponding decrease to the deferred natural gas cost accounts of approximately $36 million as of Jan. 1, 2004. Of this amount, $33 million related to current natural gas storage inventory and $3 million related to long-term natural gas storage inventory. As natural gas costs are 100 percent recoverable for PSCo’s local natural gas distribution operations under PSCo’s natural gas cost adjustment mechanism, the cumulative effect of this change had no impact on net income. Prior period financial statements were not restated since the CPUC authorized this change effective Jan. 1, 2004. Under the natural gas cost adjustment mechanism, the decrease in the cost of natural gas will reduce rates to retail natural gas customers in Colorado during 2004.

Reclassifications — Certain items in the statements of operations and balance sheets have been reclassified from prior period presentation to conform to the 2004 presentation. These reclassifications had no effect on net income.

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 proceeding 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 methodology to assess generation market power and modified measures to mitigate market power where it is found. The FERC upheld and clarified the interim requirements on rehearing in an order issued July 8, 2004. This methodology is to be applied to all initial market-based rate applications and triennial reviews. Under this methodology, the FERC has adopted two indicative screens (an uncommitted pivotal supplier analysis and an uncommitted market share analysis) to assess market power. Passage of the two screens creates a rebuttable presumption that an applicant does not have market power, while the failure creates a rebuttable presumption that the utility does have market power. An applicant or intervenor can rebut the presumption by performing a more extensive delivered-price test analysis. 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 areas where an applicant is found to have market power. The Utility Subsidiaries are reviewing the new interim requirements to determine what, if any, impact they will have on their wholesale market-based rate authority.

The Utility Subsidiaries are required to file an updated market power analysis using the new interim market power screens on or before Feb. 7, 2005. As a related matter, in addition to the triennial update filing, PSCo and SPS were required by the FERC, in its orders addressing the merger to form New Century Energies, Inc. in 1997, to file a supplemental market power analysis six months prior to the completion of the inter-tie transmission line between their systems to address the competitive impacts of that project. PSCo and SPS filed the required supplemental analysis on July 20, 2004. The FERC issued a notice of the filing of this supplemental analysis and no party filed comments. On Oct. 6, 2004, the FERC issued a notice of proposed rulemaking proposing to require electric utilities with market-based rates to file a “change in status report” regarding changes in transmission or generation ownership or operation that could affect eligibility for market-based rates. The change, if adopted, is not expected to go into effect in 2004.

Department of Energy Blackout Report - On April 6, 2004, the U.S. Department of Energy (DOE) 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 recommended 46 specific changes to current statutes, rules or practices in order to improve the reliability of the infrastructure used to transmit electric power. The recommendations included the establishment of mandatory reliability standards and financial penalties for noncompliance. On April 14, 2004, the 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. The Utility Subsidiaries submitted the required report on their vegetation management practices to the FERC in June 2004. 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.

Generation Interconnection Rules - On June 25, 2004, the FERC issued an order rejecting in part the April 2004 Xcel Energy compliance filing, regarding its Utility Subsidiaries, to FERC Order No. 2003-A, a FERC rule requiring all jurisdictional electric utilities to adopt uniform interconnection procedures and a standard form interconnection agreement for new generators of 20 megawatts or more. Xcel Energy had proposed very limited modifications to the pro forma procedure mandated by the FERC to facilitate compliance by PSCo with Colorado state least cost planning (LCP) rules, which require PSCo to analyze its loads and resource needs and select the least cost resource portfolio taking into account both generation and transmission costs. Xcel Energy argued the limited variations were necessary for PSCo to comply with both Order No. 2003-A and the Colorado LCP rules. The FERC accepted the portions of the compliance filing adopting the pro forma process and agreement, but rejected the variations as contrary to Order No. 2003-A. On July 26, 2004, Xcel Energy requested rehearing of the FERC order and submitted a compliance filing to the June 25^th order. On Aug. 27, 2004, the FERC issued an order approving the compliance filing. On Sept. 27, 2004, Xcel Energy filed a request for rehearing in order to preserve the July 26^th request for rehearing. On Oct. 27, 2004, the FERC accepted the proposed tariff changes on rehearing, subject to certain conditions. The 2003 PSCo LCP proposal is pending before the CPUC and is expected to be supplemented to address the bid evaluation process.

Midwest ISO Transmission and Energy Markets Tariff (NSP-Minnesota and NSP-Wisconsin) — On March 31, 2004, the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) regional transmission organization filed its proposed transmission and energy markets tariff (TEMT), 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 TEMT. The Midwest ISO proposed a Dec. 1, 2004 effective date.

On May 26, 2004, the FERC issued an initial procedural order. The FERC found that certain pre-Order 888 “grandfathered” agreements (GFAs) for transmission service could negatively affect implementation of the TEMT, so FERC delayed the effective date of the energy market to March 1, 2005. The FERC also set the issue of the GFAs for an expedited hearing process. NSP-Minnesota and NSP-Wisconsin submitted compliance filings regarding their approximately 50 GFAs on June 25, 2004. Approximately 10 GFAs were disputed, and hearings were held June 30, 2004 and July 1, 2004. The other GFAs are not disputed. The primary disputed issues related to responsibility for TEMT charges for loads served under the GFAs. The Administrative Law Judge (ALJ) submitted an initial decision to the FERC on July 29, 2004, recommending that NSP-Minnesota and NSP-Wisconsin generally be the entity financially responsible for TEMT costs for GFAs. On Sept. 16, 2004, the FERC issued an order largely upholding the ALJ’s initial decision. On Oct. 18, 2004, NSP-Minnesota and NSP-Wisconsin requested rehearing of the FERC order, arguing the order erroneously required NSP-Minnesota and NSP-Wisconsin to be the financially responsible entity and noting several errors in the order. A final decision is expected later in 2004.

On Aug. 6, 2004, after completion of the GFA hearings and submission of the ALJ report, the FERC issued its initial substantive order regarding the TEMT. The FERC approved the TEMT and reaffirmed the March 1, 2005 effective date, but ordered various changes to the filed tariff. On Sept. 7, 2004, numerous requests for rehearing were filed contesting various FERC decisions.

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 wholesale power costs. However, NSP-Minnesota and NSP-Wisconsin oppose certain aspects of the TEMT as proposed, and believe the Midwest ISO should implement the new market mechanisms only after it demonstrates that it will protect reliability. Xcel Energy cannot at this time estimate the total financial impact of the new market structure. Xcel Energy also cannot predict at this time whether the numerous remaining issues will be resolved in time to allow the Midwest ISO market to commence on March 1, 2005, as proposed.

Midwest ISO Long Term Pricing Proposals Filed (NSP-Minnesota and NSP-Wisconsin) – On Oct. 1, 2004, in response to 2002 and 2003 FERC orders requiring elimination of regional through-and-out rate surcharges (RTORs), two competing proposals were filed to establish term transmission pricing in the combined regions served by the Midwest ISO and PJM Interconnection, Inc. (PJM). Approximately 60 transmission owners in the combined region, including NSP-Minnesota and NSP-Wisconsin, support the “Unified Plan” proposal, which would retain most aspects of existing Midwest ISO transmission rate design and make certain transition payments to utilities affected by elimination of the RTORs through 2008. Other transmission owners, including American Electric Power Co. and Commonwealth Edison, support the competing Regional Pricing Plan (RPP) proposal, which would charge a greater share of transmission costs to utilities that are net importers of electricity. The proposed changes would be effective Dec. 1, 2004. On Sept. 27, 2004, the FERC also initiated a complaint proceeding under Section 206 of the Federal Power Act against all transmission owning utilities in the Midwest ISO and PJM regions, including NSP-Minnesota and NSP-Wisconsin, to establish a Dec. 1, 2004 refund date for its final decision on long term pricing. Elimination of the RTOR is expected to reduce transmission revenues to NSP-Minnesota and NSP-Wisconsin by approximately $3 million per year. The Unified Plan would require NSP-Minnesota and NSP-Wisconsin to contribute approximately $750,000 to transition payments in 2005. The effect of the RPP proposal is not fully known at this time. The FERC has indicated that it will act on the competing proposals before Dec. 1, 2004.

Private Fuel Storage (NSP-Minnesota) - NSP-Minnesota is part of a consortium of private parties working to establish a private facility for interim storage of spent nuclear fuel. In 1997, Private Fuel Storage, LLC filed a license application with the Nuclear Regulatory Commission (NRC) for a temporary storage site for spent nuclear fuel on the Skull Valley Indian Reservation in Utah. Most issues raised by opponents were favorably resolved or dismissed, however, the likelihood of certain aircraft crashes into the proposed facility was deemed sufficiently credible to be addressed. On May 11, 2004, the NRC issued a safety evaluation report documenting its evaluation of aircraft crash consequences on casks at the proposed private storage facility. The report concluded that an accidental aircraft or ordnance impact at the proposed facility does not pose a credible hazard to public health and safety. The Atomic Safety and Licensing Board (ASLB) hearings were completed in September 2004. The ASLB is expected to forward their recommendation to the NRC commissioners in January 2005, and a license could be issued in early 2005.

Minnesota Service Quality Investigation (NSP-Minnesota) - 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 contained 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. On June 2, 2004, NSP-Minnesota submitted a compliance tariff implementing the terms of the MPUC order, including modifications to the settlement. On Sept. 17, 2004, the MPUC issued an order accepting NSP-Minnesota’s compliance tariff as consistent with the modifications of the settlement contained in its March 10, 2004 order. On Sept. 27, 2004, NSP-Minnesota formally accepted the MPUC’s modifications to the settlement. NSP-Minnesota is now in the process of implementing various aspects of the settlement, including the $1 million refund to customers that experienced long duration outages in 2002 and 2003. The payment is scheduled to be made in November 2004.

NRG Energy, Inc. (NRG) Tax Complaint (NSP-Minnesota) - In November 2003, an NSP-Minnesota customer filed a complaint with the MPUC alleging that ratepayers are entitled to a share of the tax benefits attributable to NRG, previously a wholly owned subsidiary of Xcel Energy. The customer subsequently supplemented this complaint with sufficient signatures from customers to warrant a formal complaint process by the MPUC. NSP-Minnesota responded to the complaint, arguing that the requested treatment is not allowed by law and is inconsistent with the MPUC’s directives to ensure full separation of NSP-Minnesota and NRG. In August 2004, the MPUC decided not to pursue this complaint. The MPUC affirmed the long-standing precedent to view each utility as a stand-alone business that does not experience positive or negative effects from its affiliates. Reconsideration of the MPUC decision has been requested by the customers that filed the complaint. NSP-Minnesota has asked the MPUC to reject this request.

NSP-Minnesota Retail Gas Rate Case - On Sept. 17, 2004, NSP-Minnesota submitted a natural gas general rate increase request to the MPUC. This is the first general rate case filed by NSP-Minnesota since late 1997. The filing requests an overall increase in annual revenues of $10 million, exclusive of natural gas supply costs, or a 1.7 percent increase. The filing also requests an interim rate increase of $6.6 million while the MPUC considers the rate request. On Sept. 29, 2004, the Minnesota Department of Commerce (DOC) filed a report indicating the rate case filing is substantially complete and may be assigned for contested case hearings. On Oct. 18, 2004, the DOC filed a subsequent report concluding NSP-Minnesota’s filing was not complete, as it needed to be corrected for a perceived error resulting from the inclusion of a purchased gas adjustment true-up balance in the financial schedules submitted with the case. Although NSP-Minnesota disputes that the inclusion of this data is an error, it made a supplemental filing on Oct. 21, 2004 to remove this data and reiterated its request that interim rates be placed in effect on Dec. 1, 2004. On Nov. 4, 2004, the MPUC accepted the rate case as supplemented by the Oct. 22, 2004 filing and approved the implementation of an annual interim rate increase of $6.4 million effective Dec. 1, 2004.

NSP-Minnesota Nuclear Plant Re-licensing – On Aug. 25, 2004, the Xcel Energy board of directors authorized the pursuit of renewal of the operating licenses for the Monticello and Prairie Island nuclear plants. Monticello’s current 40-year license expires in 2010, and Prairie Island’s licenses for its two units expire in 2013 and 2014. Applications for Monticello are planned to be filed with the MPUC in the winter of 2004 seeking a certificate of need for dry spent fuel storage and early in 2005 with the NRC for an operating license extension of up to 20 years. A decision regarding Monticello re-licensing is expected in 2007. Plant assessments and other work for the Prairie Island applications are planned in the next two or three years.

NSP-Minnesota Resource Plan – On Nov. 1, 2004, NSP-Minnesota filed its 2004 resource plan with MPUC. The resource plan projects a 3,100 megawatt shortage of electricity during the next 15 years, based on an anticipated growth in demand of 1.65 percent annually, or approximately 150 megawatts per year, during the period. The resource plan:

• identifies the need for adding up to 1,125 megawatts of new base-load electricity generation by 2015;

• recommends and begins pursuit of a new resource acquisition process that includes multiple options for consideration, including generation built by NSP-Minnesota;

• recommends increasing energy-saving goals for demand-side energy management programs by nearly 17 percent;

• recommends extending the operating licenses for the Prairie Island and Monticello nuclear plants by 20 years (NSP-Minnesota plans to apply for a certificate of need in Minnesota for a dry spent-fuel storage facility at the Monticello plant, to file an application with the federal government to extend the Monticello plant’s license in early 2005 and to make similar filings for the Prairie Island plant in 2008.);

• assumes nearly 1,700 megawatts of wind power on NSP-Minnesota’s system;

• identifies the need for obtaining up to 550 megawatts of new power resources for peak usage times by 2015 depending on the amount and timing of any base-load resources acquired and

• cites the importance of ensuring that sufficient transmission resources are available to move electricity from generation sources.

The MPUC is expected to solicit comments from interested parties and may hold hearings during which members of the public can express their views. A decision on the plan is expected within a year.

NSP-Wisconsin Fuel Cost Recovery Filing - On Aug. 2, 2004, NSP-Wisconsin filed an application with the Public Service Commission of Wisconsin (PSCW) to reopen its 2004 rate case for the limited purpose of resetting 2005 electric fuel monitoring costs, and to authorize an increase in Wisconsin retail electric rates to recover forecast increases in fuel and wholesale market purchased energy costs. In its application, NSP-Wisconsin indicated an increase of $17.3 million is necessary to avoid under- recovering its 2005 fuel costs based on the most recent forecast. NSP-Wisconsin is requesting the PSCW approve new electric base rates effective Jan. 1, 2005. The application is currently being reviewed with PSCW staff auditors. A hearing on the application has been scheduled for Nov. 18, 2004.

NSP-Wisconsin 2004 Fuel Cost Recovery- Potential Rate Reduction Proceeding - On Aug. 2, 2004 the PSCW issued an order to reopen NSP-Wisconsin’s 2004 rate case. In its decision, the PSCW ordered NSP-Wisconsin’s current rates be made subject to refund pending a full review and final determination of the reasonableness of electric fuel costs. NSP-Wisconsin’s actual 2004 fuel costs through September are 2.9 percent lower than the fuel costs that were authorized in NSP-Wisconsin’s 2004 rate order and are being recovered in base rates. The lower fuel costs are primarily due to lower customer load caused by abnormal weather and higher sales to other utilities. However, despite the year-to-date over-recovery, NSP-Wisconsin forecasts higher costs for the fourth quarter of the year, and expects to end the year within the 2 percent annual bandwidth allowed. Based on this data, NSP-Wisconsin expects to argue in the proceeding that a rate decrease is not warranted. Should the PSCW find that a rate decrease is warranted, the refund would be limited to the net difference between current rates and final rates set by the PSCW, plus carrying costs, between Aug. 4, 2004 and the date final rates are set.

PSCo Least-Cost Resource Plan - On April 30, 2004, PSCo filed its 2003 least-cost resource plan (LCRP) with the CPUC. PSCo has identified that it needs to provide for 3,600 megawatts of capacity through 2013 to meet load growth and replace expiring contracts. The LCRP identifies the resources necessary to meet PSCo’s estimated load requirements. Of the amount needed, PSCo believes 2,000 megawatts will come from new resources, and 1,600 megawatts will come from entering into new contracts with existing suppliers whose contracts expire during the resource acquisition period.

As part of its resource plan, PSCo is seeking the waiver of certain CPUC rules, which would allow it to build a new 750 megawatt coal-fired unit at its existing Comanche power plant site located in Pueblo, Colo. PSCo plans to own 500 megawatts of this new facility. Two of 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.

On April 30, 2004, PSCo also filed an application requesting a certificate of public convenience and necessity for the new coal unit. PSCo also filed a separate application for a specific regulatory plan to address the impacts of purchased capacity contracts on its capital structure and to accelerate the recovery of the costs of financing the new power plant and related transmission prior to commercial operations. The CPUC has consolidated these three applications. Intervenor testimony was filed in September 2004, and PSCo filed its rebuttal testimony in October 2004. A decision is expected in late 2004 or early 2005. The procedural schedule is as follows:

•	Hearings	Nov. 1 – 19
•	Statements of Position	Dec. 3
•	Commission Decision	Dec. 15 – Jan. 15

In a separate docket, the CPUC granted PSCo’s request for approval of a 500-megawatt renewable energy solicitation. PSCo issued a request for proposal, with bids to be submitted in November 2004.

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 will recover purchased capacity payments to power suppliers that are not included in the determination of PSCo’s base electric rates determined in its 2002 general rate case or other recovery mechanisms. In May 2004, the CPUC granted the PSCo PCCA application, in part with new rates effective June 1, 2004. Primary provisions of the initial CPUC ruling included a capped PCCA recovery for the period June 1, 2004 through Dec. 31, 2006 at PSCo’s current predicted capacity payments for a group of specific contracts, which will provide recovery of $20.4 million in 2004, $33.5 million in 2005 and $19.8 million in 2006. In addition, the CPUC excluded seven of the existing contracts from incremental recovery under the PCCA calculation. However, PSCo expects that the capacity costs from these contracts will be eligible for recovery through base rates when PSCo files its next general rate case. The energy costs from these contracts are eligible for recovery through the PSCo electric commodity adjustment clause.

On July 16, 2004, PSCo filed an Application for Rehearing, Reargument and Reconsideration (ARRR) asking the CPUC to grant rehearing on its decision specifying that the PCCA recovery be limited to budget estimates of purchased capacity costs, instead asking for full recovery of actual purchased capacity payments. Second, the ARRR requested that the CPUC modify its decision to allow PSCo to reflect the relationship of the Air Quality Improvement Rider (AQIR) to the 2004 PCCA rider eliminating the actual amount of double recovery of purchased capacity expense that results from the interaction of PSCo’s AQIR and the PCCA. The existing CPUC decision assumes a double recovery, which is $750,000 greater than the actual amount. On Oct. 27 2004, the CPUC granted in full PSCo’s rehearing request, removing the restrictions in the CPUC’s earlier decision in order to allow PCCA recovery of the actual purchased capacity payments made under the allowed contracts. The CPUC also agreed that PSCo’s proposed AQIR credit to the PCCA was calculated appropriately, reversing the CPUC’s earlier decision that overstated the credit by $750,000.

PSCo Electric Department Earnings Test Proceedings - As a part of PSCo’s annual electric earnings test, the CPUC has opened a docket to consider whether PSCo’s cost of debt has been adversely affected by the financial difficulties at NRG and, if so, whether any adjustments to PSCo’s cost of capital are appropriate. In its earnings test for 2002, PSCo did not earn above its allowed authorized return on equity and, accordingly, has not recorded any refund obligations. There was no earnings test for 2003.

On May 28, 2004, the CPUC staff and the Office of Consumer Counsel (OCC) filed testimony recommending the CPUC order the use of a pro forma regulatory adjustment to the cost of debt on $600 million of debt issued by PSCo in September 2002, reducing the cost of debt in this and future proceedings. The CPUC staff recommendation would result in an exclusion of interest costs of $12 million and the OCC recommendation would result in an exclusion of $17 million. PSCo does not anticipate its 2002 earnings will be above

its allowed authorized return on equity with these recommended changes in the cost of debt. Hearings are scheduled in December 2004.

PSCo Quality of Service Plan- The PSCo quality of service plan (QSP) provides for bill credits to Colorado retail customers, if PSCo does not achieve certain operational performance targets. During the second quarter of 2004, PSCo filed its calendar year 2003 operating performance results for electric service unavailability, phone response time, customer complaints, accurate meter reading and natural gas leak repair time measures. PSCo did not achieve the 2003 performance targets for the electric service unavailability measure or the customer complaint measure. Additionally, PSCo filed revisions to its previously filed 2002 electric QSP results for the service unavailability measure. Based on the revised results, PSCo did not achieve the 2002 performance targets for the electric service unavailability measure, creating a bill credit obligation for 2002 and increasing the maximum bill credit obligation for subsequent years’ performance.

As of Dec. 31, 2003, PSCo had accrued an aggregate estimated bill credit obligation of $6.4 million for the 2002 and 2003 calendar years. Based on the updated information and filings discussed above, during the second quarter of 2004, PSCo increased its estimated bill credit liability for these years to $13.4 million. PSCo posted the bill credits to retail customer accounts in the third quarter of 2004. For calendar year 2004, PSCo has evaluated its year to date performance under the QSP and has recorded an additional liability of $4.2 million for the nine months ended Sept. 30, 2004. Under the electric QSP, the estimated maximum potential bill credit obligation for calendar 2004 performance is approximately $15.2 million, assuming none of the performance targets are met.

PSCo Reliability Inquiry - The CPUC staff and the Colorado OCC each submitted final reports to the CPUC based on the results of an informal investigation of the reliability of PSCo’s electric distribution system. The staff report recommends that the CPUC review the existing QSP to ensure that the plan provides adequate incentives for PSCo to provide reliable electric service throughout its Colorado service territory. In addition, the staff recommends that the CPUC review the results of PSCo’s 2004 action plan to address certain localized reliability problems that occurred in 2003. The OCC’s consultant recommended that the CPUC initiate an independent performance assessment of PSCo’s electric distribution system and related business practices. PSCo submitted its response to the final reports of the staff and the OCC in August 2004. The CPUC is expected to issue a final order regarding the reliability investigation within the next few months.

PSCo Electric Trading Docket - As part of the settlement of the 2002 PSCo general rate case, the parties agreed that PSCo would initiate a docket regarding the status of electric trading after 2004. The proceeding was initiated on Jan. 30, 2004. PSCo’s testimony proposed certain revisions to the business rules governing trading transactions; to continue electric trading on both a generation book and commodity book basis; to establish a defined trading benefit for electric retail customers and to begin trading natural gas as a risk mitigation measure in support of its electric trading. On July 8, 2004, the staff of the CPUC filed testimony regarding electric trading. The staff has raised issues related to the computer model used to allocate costs to trading transactions, PSCo’s ability to track transactions individually, instead of in aggregate, for each hour and the allocation of system costs. The staff requested additional reporting through 2006.

PSCo, the staff of the CPUC and the OCC reached full settlement of the disputed issues on Sept. 10, 2004. The CPUC approved the settlement on Oct. 5, 2004. The settlement modifies the rules governing trading transactions to provide more specificity as to transaction priorities, record retention and cost assignment. The settlement provides for continuation of electric commodity trading as currently conducted by PSCo, and permits PSCo to begin trading natural gas as a risk mitigation measure in support of its electric trading. The settlement also provides for the margin sharing mechanisms that are currently in place in the PSCo retail rates to continue through 2006. Finally, the settlement requires the cooperative development of auditing processes to provide the staff of the CPUC with information regarding PSCo’s trading operations and for the filing of monthly reports with respect to these trading operations.

California Refund Proceeding (PSCo) - A number of parties purchasing energy in markets operated by the California Independent System Operator (California ISO) or the California Power Exchange (PX) have asserted prices paid for such energy were unjust and unreasonable and that refunds should be made in connection with sales in those markets for the period Oct. 2, 2000 through June 20, 2001. PSCo supplied energy to these markets during this period and has been an active participant in the proceedings. The FERC ordered an investigation into the California ISO and PX spot markets and concluded that the electric market structure and market rules for wholesale sales of energy in California were flawed and have caused unjust and unreasonable rates for short-term energy under certain conditions. The FERC ordered modifications to the market structure and rules in California and established an ALJ to make findings with respect to, among other things, the amount of refunds owed by each supplier based on the difference between what was charged and what would have been charged in a more functional market, i.e., the “market clearing price,” which is based on the unit providing energy in an hour with the highest incremental cost. The initial proceeding related to California’s demand for $8.9 billion in

refunds from power sellers. The ALJ subsequently stated that after assessing a refund of $1.8 billion for power prices, power suppliers were owed $1.2 billion because the state was holding funds owed to suppliers. Because of the low volume of sales that PSCo had into California after this date, PSCo’s exposure is estimated at approximately $3.4 million, which is offset by amounts owed by the California ISO to PSCo in excess of that amount.

Certain California parties sought rehearing of this decision. Among other things, they asserted that the refund effective date should be set at an earlier date. They have based this request in part on the argument that the use by sellers of certain trading strategies in the California market resulted in unjust and unreasonable rates, thereby justifying an earlier refund effective date. The FERC subsequently allowed the purchasing parties to request from sellers, including PSCo, additional information regarding the market participants’ use of certain strategies and the effect those strategies may have had on the market. Based on the additional information they obtained, these purchasing entities argued to the FERC that use of these strategies did justify an earlier refund effective date. These California entities have contended that PSCo would owe approximately $17 million in refunds, if the FERC set the earlier refund effective date. In October 2003, the FERC determined that the refund effective date should not be reset to an earlier date, and gave clarification of how refunds should be determined for the previously set refund period. Certain California parties appealed the FERC’s decision not to establish an earlier refund effective date to the United States Court of Appeals for the Ninth Circuit.

In a related case, certain California parties also appealed the FERC orders dismissing a complaint by the California Attorney General challenging market-based rates as inconsistent with the Federal Power Act. The California Attorney General also argued that wholesale sellers, including PSCo, were violating their market-based rate authorizations by not reporting their market-based sales on an individual transaction basis. Prior to a clarification of its rules, most sellers, including PSCo, reported their transactions on an aggregate basis. On Sept. 9, 2004, the United States Court of Appeals for the Ninth Circuit issued an opinion rejecting the California Attorney General’s general challenge to market-based rates, but agreeing with its challenge regarding the failure to report individual transactions. It remanded the case to the FERC to consider action to take to address these failures and indicated that the FERC could require refunds.

PSCo and SPS FERC Transmission Rate Case - On Sept. 2, 2004, and as amended on Oct. 13, 2004, Xcel Energy filed on behalf of PSCo and SPS an application to increase wholesale transmission service and ancillary service rates within the Xcel Energy joint open access transmission tariff. PSCo and SPS are seeking an increase in annual transmission service and ancillary services revenues of $6.1 million. As a result of a settlement with certain PSCo wholesale power customers in 2003, power rates would be reduced by $1.4 million. The net increase in annual revenues proposed is $4.7 million, effective Dec. 13, 2004. The rate increase application also includes PSCo and SPS adopting an annual formula rate for transmission service pricing as previously approved by the FERC for other transmission providers. The filing is pending FERC review.

FERC Standards of Conduct, Code of Conduct and Open Access Transmission Tariff Audit (PSCo) — On Oct. 27, 2004, the FERC notified Xcel Energy that it intends to commence an audit to determine whether PSCo has complied with certain FERC requirements during the period Jan. 1, 2002 through Aug. 31, 2004. The audit will focus on compliance with standards of conduct, codes of conduct and open access transmission tariff provisions. The FERC provided an initial data request for which responses are due Nov. 12, 2004. The audit is a routine practice of the FERC, and PSCo does not expect a material financial or operational impact as a result of the audit.

SPS Texas Fuel Cost Recovery — Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor. In May 2004, SPS filed its periodic request for fuel and purchased power cost recovery for electric generation and fuel management activities for the period from January 2002 through December 2003. SPS requested to recover approximately $580 million of Texas-jurisdictional fuel and purchased power costs for the two-year period. The proceeding has been set for hearing in December 2004, and a decision regarding SPS fuel and purchased power costs incurred through December 2003 is expected in the third quarter of 2005.

In November 2003, SPS submitted a fuel cost surcharge factor application in Texas to recover an additional $25 million of fuel cost under-recoveries accrued during June through September 2003. In February 2004, the parties in the proceeding submitted a unanimous settlement allowing SPS to collect net under-recoveries experienced through December 2003 of $22 million. The surcharge, which was approved by the Public Utility Commission of Texas (PUCT) in March 2004, went into effect May 2004 and will continue for 12 months.

In May 2004, SPS filed another fuel cost surcharge factor application in Texas to recover an additional $32 million of fuel cost recoveries accrued during January through March 2004. In June 2004, the parties in the proceeding submitted a unanimous settlement allowing SPS to collect the $32 million fuel cost under-recoveries surcharge factors for a 12-month period beginning November 2004. The PUCT approved the settlement in September 2004.

On Nov. 5, 2004, SPS submitted another fuel cost surcharge application with the PUCT for $30 million of fuel cost under-recoveries accrued from April 2004 through September 2004. These under-recoveries under the Texas retail fixed fuel collection process are primarily the result of higher than expected natural gas prices. SPS is also proposing in its November 2004 filing to increase its semi-annual fuel factors to take into account the increased cost of natural gas at its gas-fueled power plants.

Southwest Power Pool (SPP) Restructuring (SPS) – SPS is a member of the SPP regional reliability council, and SPP acts as tariff administrator for the SPS system. In October 2003, SPP filed for FERC authorization to transform its operation into a regional transmission organization (RTO) under FERC Order No. 2000. In addition, SPP made unilateral changes to the existing SPP membership agreement, which increases the current costs of SPS membership in SPP by approximately $1.5 million per year, in order to fund the start of RTO operations. On Feb. 10, 2004, the FERC conditionally approved SPP’s proposed formation as an RTO, subject to SPP meeting certain requirements. On Oct. 1, 2004, the FERC issued a further order granting the SPP status as an RTO. On Oct. 31, 2003, SPS submitted a conditional notice of withdrawal from SPP in order to preserve flexibility with regard to future RTO membership. However, the Feb. 10, 2004 order also provides that SPS may only terminate its current membership in SPP with FERC approval. The FERC upheld this decision in a rehearing order issued Oct. 1, 2004. SPS will be required to transfer functional control of its electric transmission system to SPP and take all transmission services, including services required to serve retail native loads, under the SPP regional tariff.

FERC Wholesale Power Rate Complaint (SPS) – On Nov. 2, 2004, Golden Spread Electric Cooperative (Golden Spread) filed a wholesale power rate complaint against SPS. The complaint alleges that SPS cost-based wholesale full-requirements and partial-requirements power rates are excessive, unjust and unreasonable. Golden Spread proposes demand charges be reduced from $4.45 per kilowatt per month to $3.41, which results in a $3.9 million reduction in annual base revenue for SPS. Included as complainants are other New Mexico cooperatives, for which the complaint does not quantify the impact. SPS estimates the impact of reduced rates for the New Mexico cooperatives and the only other full-requirements wholesale customer of SPS would be a reduction of revenue of approximately $3.6 million. Golden Spread requested a hearing be scheduled with a refund effective date of Jan. 1, 2005.

3. Tax Matters — Corporate-Owned Life Insurance (PSCo)

Interest Expense Deductibility – PSCo’s wholly owned subsidiary, PSR Investments, Inc. (PSRI), owns and manages permanent life insurance policies on some of PSCo’s employees, known as corporate-owned life insurance (COLI) policies. 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 Internal Revenue Service (IRS) has challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through 1999.

After consultation with tax counsel, Xcel Energy contends that the IRS determination is not supported by tax law. Based upon this assessment, management believes 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.

Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2004, would reduce earnings by an estimated $317 million. In the third quarter of 2004, PSCo received formal notification that the IRS will seek penalties. If penalties (plus associated interest) are also included, the total exposure through Dec. 31, 2004, increases to approximately $380 million. At Sept. 30, 2004, PSCo estimates its annual earnings for 2004 would be reduced by $35 million, after tax, if COLI interest expense deductions were no longer available.

Accounting for Uncertain Tax Positions – In late July 2004, the FASB discussed potential changes or clarifications in the criteria for recognition of tax benefits, which may result in raising the threshold for recognizing tax benefits, which have some degree of uncertainty. The FASB has not issued any proposed guidance, but has indicated that it expects to in the fourth quarter of 2004. PSCo

is unable to determine the impact or timing of any potential accounting changes required by the FASB, but such changes could have a material financial impact.

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

Environmental Contingencies

The Utility Subsidiaries are subject to regulations covering air and water quality, land use, the storage of natural gas and the storage and disposal of hazardous or toxic wastes. Compliance is continually assessed. Regulations, interpretations and enforcement policies can change, which may impact the cost of building and operating facilities. The Utility Subsidiaries have been or are currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, the 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, the 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, the Utility Subsidiaries would be required to recognize an expense for such unrecoverable amounts in their financial statements.

Federal Clean Water Act (NSP-Minnesota, NSP-Wisconsin, PSCo) - The Federal Clean Water Act addresses the environmental impacts of cooling water intakes. In July 2004, the Environmental Protection Agency (EPA) published phase II of the rule that applies to existing cooling water intakes at steam-electric power plants. The rule will require NSP-Minnesota, NSP-Wisconsin and PSCo to perform additional environmental studies at 12 power plants in Minnesota, Wisconsin and Colorado to determine the impact the facilities may be having on aquatic organisms vulnerable to impingement or entrainment. If the studies determine the plants are not meeting the new performance standards established by the phase II rule, physical and/or operational changes may be required at these facilities. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved. Preliminary cost estimates range from less than $1 million at some facilities to more than $10 million at others depending on site-specific circumstances. Based on the limited information available, total capital costs to NSP-Minnesota, NSP-Wisconsin and PSCo are estimated to be approximately $44 million, $6 million and $5 million, respectively. Actual costs may be significantly higher or lower depending on issues such as the resolution of outstanding third-party legal challenges to the rule.

Levee Station Manufactured Gas Plant Site (NSP-Minnesota) - A portion of NSP-Minnesota’s High Bridge plant coal yard is located on the site of the former Levee Station manufactured gas plant (MGP). The Levee Station was a coke-oven gas purification, storage and distribution facility. The Levee Station supplied manufactured gas to the city of St. Paul from 1918 to the early 1950s. In the 1950s the facility was demolished, and the High Bridge coal yard was extended onto the property. In the 1990’s, the site was investigated and partially remediated at a cost of approximately $2.9 million. In 2006, NSP-Minnesota plans to commence construction of the High Bridge Combined Cycle Generating Plant, as part of Metro Emissions Reduction Program (MERP), on the site of the Levee Station. The construction of the new plant will require the removal of buried structures and soil and groundwater remediation. Remediation activities will begin in 2005. The cost of the additional remediation is estimated to be $4.5 million.

Ashland Manufactured Gas Plant Site (NSP-Wisconsin) - On July 2, 2004, the Wisconsin Department of Natural Resources (WDNR) sent NSP-Wisconsin an invoice for recovery of past costs incurred at the Ashland site between 1994 and March 2003 in the amount of $1.4 million. On Oct. 19, 2004, the WDNR, represented by the Wisconsin Department of Justice, filed a lawsuit in Wisconsin state court for reimbursement of the past costs. NSP-Wisconsin is reviewing the invoice to determine whether all costs charged are appropriate. All appropriate insurance carriers have been notified of the WDNR’s invoice and will be invited to participate in any future efforts to address the WDNR’s actions. All costs paid are expected to be recoverable in rates.

French Island (NSP-Wisconsin) – NSP-Wisconsin’s French Island plant is required to conduct annual emissions performance tests to meet federal requirements for large municipal waste combustors. In April 2004, the annual test on one boiler was completed. In June 2004, NSP-Wisconsin received the test results, which indicated that all parameters tested, with the exception of hydrochloric acid (HCl), were below allowable levels. NSP-Wisconsin retested the unit later in June 2004 and found results that suggested that chemical interference of ammonium chloride may have caused an inaccurate result during the April test. Based on the results of the retesting, NSP-Wisconsin believes there is strong evidence to indicate the plant never exceeded the HCl limit. Under the terms of a consent decree between NSP-Wisconsin and the EPA, a failure to meet specified emission limits, including HCl, allows the EPA to pursue penalties. NSP-Wisconsin is unsure of future EPA action or penalty assessment, but pursuant to the consent order, any penalty is unlikely to exceed $300,000.

Industrial Boiler Maximum Achievable Control Technology Standards (NSP-Wisconsin and PSCo) - - On Sept. 13, 2004, the EPA published final maximum achievable control technology (MACT) standards for hazardous air pollutants from industrial boilers. Two boilers at the Bay Front plant must comply with this rule by September 2007 because they are categorized as non-fossil fuel-fired utility boilers and electric utility steam generating units less than 25 megawatts. The rule regulates hydrogen chloride, particulate

matter, mercury and opacity. NSP-Wisconsin is reviewing the rule to determine its options for compliance at Bay Front. If new environmental control equipment is required, the cost of capital improvements needed to comply with the new standard is estimated to be approximately $10 million. The MACT standards may apply to some generating units at PSCo, however evaluation of the potential impact is in a preliminary stage.

Fort Collins Manufactured Gas Plant Site (PSCo) - Prior to 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated an MGP in Fort Collins, Colo. not far from the Cache la Poudre River. In 1926, after acquiring the Poudre Valley Gas Co., PSCo shut down the gas site and, years later, sold most of the property. In the mid-1990s, contamination associated with MGP operations was discovered on the gas plant site, and PSCo paid for a portion of a partial cleanup. Recently, an oily substance similar to MGP by-products has been discovered in the Cache la Poudre River. PSCo is working with the EPA, the Colorado Department of Public Health and Environment, the current site owner and the city of Fort Collins (owner of a former landfill property between the river and the plant site) to address the substance found in the river as well as other environmental issues found on the property. In early 2004, PSCo completed implementation of a work plan to further investigate the sources of contamination of the river at a cost of approximately $1.4 million. The work resulted in removal of contaminated sediments and delineation of the extent of contamination. PSCo is currently in discussions with the EPA, the city of Fort Collins and other stakeholders regarding possible next steps. The EPA has agreed to allow PSCo to take the lead in development and evaluation of alternatives and ultimately the design of the selected alternative to address the remaining contamination in the river. This process is expected to proceed in consultation with the EPA and other stakeholders and to follow the EPA’s national contingency plan. PSCo will likely perform future remediation work for which current cost estimates for the range of alternatives is approximately $7.5 million to $9.8 million. To date, PSCo has spent approximately $2.1 million on the project, including settlement costs negotiated with Fort Collins in 1998. The EPA has also conducted work over the past two years, incurring estimated costs of approximately $1 million to date, for which they will likely seek recovery from PSCo at a future date.

While PSCo has recorded a liability of $6.2 million at Sept. 30, 2004, it lacks sufficient information at this time to determine its ultimate liability for clean up, if different, for this site. PSCo has deferred the costs recorded to date and believes that they will be recovered through future rates. Any costs that are not recoverable from customers will be expensed.

Polychlorinated Biphenyl (PCB) Storage and Disposal (SPS) - In August 2004, SPS received notice from the EPA contending SPS violated PCB storage and disposal regulations with respect to storage of a drained transformer and related solids. The EPA contends the fine for the alleged violation is approximately $1.2 million. SPS is contesting the fine and in discussions with the EPA.

Legal Contingencies

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

Carbon Dioxide Emissions Lawsuit - On July 21, 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO₂) emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO₂ is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or gas-fired power plants. The lawsuits allege that CO₂ emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO₂ emissions. In October 2004, Xcel Energy and four other utility companies filed a motion to dismiss the lawsuit contending that the lawsuit is an attempt to usurp the policy-setting role in the U.S. Congress and the president. The ultimate financial impact of these lawsuits, if any, is not determinable at this time.

Nuclear Waste Disposal Litigation (NSP-Minnesota) - The federal government has the responsibility to dispose of, or permanently store, domestic spent nuclear fuel and other high-level radioactive substances. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear substance management. This includes the siting, licensing, construction and operation of a repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive substances at a permanent storage or disposal facility. The federal government has designated the site as Yucca Mountain in Nevada. This designation has resulted in extensive litigation.

On July 9, 2004, the federal Court of Appeals for the District of Columbia issued its decision in consolidated cases challenging regulations and decisions on the federal nuclear waste program. The Court of Appeals rejected challenges by the state of Nevada and other intervenors with respect to the majority of the licensing regulations of the NRC, the congressional resolution selecting Yucca Mountain as the site of the permanent repository, and the DOE and presidential actions leading to the selection of Yucca Mountain. The Court of Appeals vacated the 10,000 year compliance period adopted by EPA regulations governing spent nuclear fuel disposal and incorporated in the NRC regulations governing Yucca Mountain licensing. NSP-Minnesota has not ascertained the impact of the decision on its nuclear operations and storage of spent nuclear fuel; however, the decision may result in additional delay and uncertainty around disposal of spent nuclear fuel.

SchlumbergerSema, Inc. vs. Xcel Energy Inc. (NSP-Minnesota) - Under a 1996 data services agreement, SchlumbergerSema, Inc. (SLB) provides automated meter reading, distribution automation, and other data services to NSP-Minnesota. In September 2002, NSP-Minnesota issued written notice that SLB committed events of default under the agreement, including SLB’s nonpayment of approximately $7.4 million for distribution automation assets. In November 2002, SLB demanded arbitration and asserted various claims against NSP-Minnesota totaling approximately $24 million for alleged breach of an expansion contract and a meter purchasing contract. In the arbitration, NSP-Minnesota asserted counterclaims against SLB including those related to SLB’s failure to meet performance criteria, improper billing, failure to pay for use of NSP-Minnesota owned property and failure to pay $7.4 million for NSP-Minnesota distribution automation assets, for total claims of approximately $41 million. NSP-Minnesota also sought a declaratory judgment from the arbitrators that would terminate SLB’s rights under the data services agreement. In August 2004, the U.S. Bankruptcy Court for the District of Delaware ruled that claims related to use of certain equipment are barred unless NSP-Minnesota can establish a basis for the claims in SLB’s conduct subsequent to the time of the assumption of the contract by SLB. Unless NSP-Minnesota can establish that basis, the decision would reduce NSP-Minnesota’s damage claim by approximately $5.5 million.

Manufactured Gas Plant Insurance Coverage Litigation (NSP-Wisconsin) — In October 2003, NSP-Wisconsin initiated discussions with its insurers regarding the availability of insurance coverage for costs associated with the remediation of four former MGP sites located in Ashland, Chippewa Falls, Eau Claire, and LaCrosse, Wis. In lieu of participating in discussions, on Oct. 28, 2003, two of NSP-Wisconsin’s insurers, St. Paul Fire & Marine Insurance Co. and St. Paul Mercury Insurance Co., commenced litigation against NSP-Wisconsin in Minnesota state district court. On Nov. 12, 2003, NSP-Wisconsin commenced suit in Wisconsin state circuit court against St. Paul Fire & Marine Insurance Co. and its other insurers. Subsequently, the Wisconsin court denied the insurers’ motion to stay the Wisconsin case pending resolution of the Minnesota action. No trial date has been set in either proceeding. The PSCW has established a deferral process whereby clean-up costs associated with the remediation of former MGP sites are deferred and, if approved by the PSCW, recovered from ratepayers. Carrying charges associated with these clean-up costs are not subject to the deferral process and are not recoverable from ratepayers. Any insurance proceeds received by NSP-Wisconsin will operate as a credit to ratepayers, therefore, these lawsuits should not have an impact on NSP-Wisconsin, and no accruals have been made.

Colorado Wildfires (PSCo) - In late October 2003, there were two wildfires in Colorado, one in Boulder County and the other in Douglas County. There was no loss of life, but there was property damage associated with these fires. Parties have asserted that trees falling into PSCo distribution lines may have caused one or both fires. Litigation was filed on Jan. 14, 2004 relating to the fire in Boulder County, in Boulder County District Court. There are now 46 plaintiffs, including individuals and insurance companies, and three co-defendants, including PSCo. The plaintiffs assert that they are seeking in excess of $35 million in damages. PSCo believes it has insurance coverage to mitigate the liability in this matter. The ultimate financial impact to PSCo is not determinable at this time.

Lamb County Electric Cooperative (SPS) - On July 24, 1995, Lamb County Electric Cooperative, Inc. (LCEC) petitioned the PUCT for a cease and desist order against SPS alleging that SPS was unlawfully providing service to oil field customers in LCEC’s certificated area. On May 23, 2003, the PUCT issued an order denying LCEC’s petition based on its determination that SPS was granted a certificate in 1976 to serve the disputed customers. LCEC appealed the decision to the District Court in Travis County, Texas and on Aug. 12, 2004, the District Court affirmed the decision of the PUCT. On Sept. 9, 2004, LCEC appealed the District Court’s decision to the Court of Appeals for the Third Supreme Judicial District of the state of Texas, which appeal is currently pending. On Oct. 18, 1996, LCEC filed a suit for damages against SPS in the District Court in Lamb County, Texas, based on the same facts alleged in the petition for a cease and desist order at the PUCT. This suit has been dormant since it was filed, awaiting a final determination at the PUCT of the legality of SPS providing electric service to the disputed customers.

Other Contingencies

Natural Gas Customer Billing Errors (NSP-Minnesota) - In July 2004, NSP-Minnesota made a filing with the MPUC that identified a number of natural gas customers in Minnesota and North Dakota that were either over- or under-billed because of an incorrect setting on a wireless meter reading device installed on customer meters beginning in late 1998. The incorrect setting occurred when the wireless remote devices were attached to older meters, allowing them to be read remotely. Customer account reviews are substantially complete, and the total amount to be refunded is estimated to be $730,000. On Aug. 11, 2004, the Office of the Attorney General requested the MPUC order an investigation into NSP-Minnesota’s inaccurate meter readings and billing errors. On Oct. 29, 2004, NSP-Minnesota provided the MPUC with information on the status of the audit of meter reading and billing practices and requested the MPUC deny the request for an investigation.

Billing Practices Investigation (SPS) - In 2003, the New Mexico Public Regulatory Commission (NMPRC) opened an investigation of SPS’s billing practices as a result of certain customers receiving estimated billings for an extended period of time. The NMPRC ordered SPS to implement temporary billing measures for customers whose billings were estimated, which was completed in 2003. On Sept. 28, 2004, the hearing examiner issued a recommended decision. It stated that SPS is now in compliance with the required meter reading and estimated billing practices. It would require SPS to file semi-annual compliance reports regarding meter reading and estimated billing activities. The hearing examiner also recommended a penalty of $50,000, proposed by the NMPRC staff, be suspended subject to SPS’s continued compliance with meter reading and estimated billing rules. The reporting period and suspended penalty will terminate after three years of the date of the NMPRC’s issuance of a final order in this case, or the date of the NMPRC’s issuance of a final order in SPS’s next general rate case, whichever occurs first. On Oct. 12, 2004, the NMPRC adopted the hearing examiner’s recommended decision.

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 and Note 3 of this Quarterly Report on Form 10-Q, appropriately represent, in all material respects, the current status of their respective commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference.

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

NSP-Minnesota

NSP-Minnesota replaced its $275 million secured credit facility, which expired in May 2004, with a $300 million unsecured, 364-day credit agreement. The new facility includes a term-out provision and one financial ratio covenant in the form of a debt to total capitalization ratio. At Sept. 30, 2004, NSP-Minnesota had no short-term debt outstanding.

PSCo

PSCo replaced its $350 million secured credit facility, which expired in May 2004, with a $350 million unsecured, 364-day credit agreement. The new facility includes a term-out provision and one financial ratio covenant in the form of a debt to total capitalization ratio. At Sept. 30, 2004, PSCo had $27 million of short-term debt outstanding at a weighted average interest rate of 4.75 percent.

SPS

At Sept. 30, 2004, SPS had $45 million of short-term debt outstanding at a weighted average interest rate of 2.55 percent.

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

The Utility Subsidiaries record all derivative instruments on their balance sheets 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 - “Accounting for Derivative Instruments and Hedging Activities,” 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 the Utility Subsidiaries’ Other Comprehensive Income, included as a component of stockholder’s equity, are detailed in the following tables:

	Nine Months Ended Sept. 30, 2004
(Millions of Dollars)	NSP- Minnesota			NSP- Wisconsin			PSCo			SPS
Balance at Jan. 1, 2004	$	—		$	(1.1	)	$	17.2		$	(7.2	)
After-tax net unrealized gains related to derivatives accounted for as hedges	0.1			—			6.0			0.9
After-tax net realized (gains) losses on derivative transactions reclassified into earnings	(0.1		)	—			(7.6		)	0.7
Accumulated other comprehensive income (loss) related to cash flow hedges — Sept. 30, 2004	$	—		$	(1.1	)	$	15.6		$	(5.6	)

	Nine Months Ended Sept. 30, 2003
(Millions of Dollars)	NSP- Minnesota		NSP- Wisconsin			PSCo			SPS
Balance at Jan. 1, 2003	$	—	$	—		$	1.0		$	(4.6	)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges	—		(1.1		)	17.6			(3.5		)
After-tax net realized (gains) losses on derivative transactions reclassified into earnings	—		—			(1.0		)	0.4
Accumulated other comprehensive income (loss) related to cash flow hedges — Sept. 30, 2003	$	—	$	(1.1	)	$	17.6		$	(7.7	)

Cash Flow Hedges

NSP-Minnesota, NSP-Wisconsin, PSCo and SPS 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 Sept. 30, 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 natural gas purchased for resale. As of Sept. 30, 2004, NSP-Minnesota and PSCo had no amounts accumulated in Other Comprehensive Income related to commodity cash flow hedge contracts that are expected to be recognized 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.

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 Sept. 30, 2004, NSP-Wisconsin had net losses of $0.1 million, PSCo had net gains of $1.5 million and SPS had net losses of $0.8 million, respectively, accumulated in Other Comprehensive Income related to interest rate 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, hedging transactions for natural gas purchased for resale are recorded as a component of natural gas 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 natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility, as discussed in Note 12 to the consolidated financial statements reported in the Utility Subsidiaries’ Annual Reports on Form 10-K for the year ended Dec. 31, 2003. There was no hedge ineffectiveness in the third 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 as a component of Operating Revenues on the Consolidated Statements of Income.

PSCo also enters into certain commodity-based transactions, not included in trading operations, which do not qualify for hedge accounting treatment. These derivative instruments are accounted for on a mark-to-market basis in the Consolidated Statements of Income. The results of these transactions are recorded within Operating Expenses on the Consolidated Statements of Income.

Normal Purchases or Normal Sales Contracts

The 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 that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that meet the requirements of normal are documented and exempted from the fair value accounting and reporting requirements of SFAS No. 133.

The 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)

The 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

(Thousands of Dollars)	Regulated Electric Utility		Regulated Natural Gas Utility			All Other			Consolidated Total
Three months ended Sept. 30, 2004
Revenues from:
External customers	$	739,049	$	60,940		$	262		$	800,251
Internal customers	218		290			—			508
Total revenue	739,267		61,230			262			800,759
Segment net income (loss)	$	72,643	$	(8,209	)	$	4,001		$	68,435

Three months ended Sept. 30, 2003
Revenues from:
External customers	$	756,629	$	54,338		$	(789	)	$	810,178
Internal customers	181		4,028			—			4,209
Total revenue	756,810		58,366			(789		)	814,387
Segment net income (loss)	$	90,314	$	(4,600	)	$	(5,304	)	$	80,410

(Thousands of Dollars)	Regulated Electric Utility		Regulated Natural Gas Utility		All Other			Consolidated Total
Nine months ended Sept. 30, 2004
Revenues from:
External customers	$	1,944,255	$	463,310	$	14,994		$	2,422,559
Internal customers	597		4,206		—			4,803
Total revenue	1,944,852		467,516		14,994			2,427,362
Segment net income	$	154,848	$	7,166	$	9,041		$	171,055

Nine months ended Sept. 30, 2003
Revenues from:
External customers	$	1,918,232	$	473,985	$	10,149		$	2,402,366
Internal customers	528		6,509		—			7,037
Total revenue	1,918,760		480,494		10,149			2,409,403
Segment net income (loss)	$	138,857	$	8,388	$	(2,743	)	$	144,502

NSP-Wisconsin

(Thousands of Dollars)	Regulated Electric Utility		Regulated Natural Gas Utility			All Other			Consolidated Total
Three months ended Sept. 30, 2004
Revenues from:
External customers	$	122,605	$	11,871		$	162		$	134,638
Internal customers	37		820			—			857
Total revenue	122,642		12,691			162			135,495
Segment net income (loss)	$	18,907	$	(1,347	)	$	92		$	17,652

Three months ended Sept. 30, 2003
Revenues from:
External customers	$	129,177	$	6,983		$	81		$	136,241
Internal customers	30		2,322			—			2,352
Total revenue	129,207		9,305			81			138,593
Segment net income (loss)	$	14,644	$	(1,620	)	$	(745	)	$	12,279

(Thousands of Dollars)	Regulated Electric Utility		Regulated Natural Gas Utility		All Other			Consolidated Total
Nine months ended Sept. 30, 2004
Revenues from:
External customers	$	354,822	$	85,812	$	479		$	441,113
Internal customers	103		2,525		—			2,628
Total revenue	354,925		88,337		479			443,741
Segment net income (loss)	$	41,857	$	1,535	$	(116	)	$	43,276

Nine months ended Sept. 30, 2003
Revenues from:
External customers	$	357,680	$	86,663	$	157		$	444,500
Internal customers	101		3,362		—			3,463
Total revenue	357,781		90,025		157			447,963
Segment net income (loss)	$	35,492	$	2,286	$	(798	)	$	36,980

PSCo

(Thousands of Dollars)	Regulated Electric Utility		Regulated Natural Gas Utility			All Other		Consolidated Total
Three months ended Sept. 30, 2004
Revenues from:
External customers	$	612,607	$	117,188		$	3,690	$	733,485
Internal customers	49		10			—		59
Total revenue	612,656		117,198			3,690		733,544
Segment net income	$	49,809	$	4,041		$	5,255	$	59,105

Three months ended Sept. 30, 2003
Revenues from:
External customers	$	588,016	$	111,151		$	4,354	$	703,521
Internal customers	58		9			—		67
Total revenue	588,074		111,160			4,354		703,588
Segment net income (loss)	$	58,164	$	(856	)	$	175	$	57,483

(Thousands of Dollars)	Regulated Electric Utility		Regulated Natural Gas Utility		All Other		Consolidated Total
Nine months ended Sept. 30, 2004
Revenues from:
External customers	$	1,628,889	$	671,460	$	18,149	$	2,318,498
Internal customers	148		50		—		198
Total revenue	1,629,037		671,510		18,149		2,318,696
Segment net income	$	98,656	$	31,302	$	12,245	$	142,203

Nine months ended Sept. 30, 2003
Revenues from:
External customers	$	1,575,108	$	529,462	$	15,723	$	2,120,293
Internal customers	201		36		—		237
Total revenue	1,575,309		529,498		15,723		2,120,530
Segment net income	$	115,146	$	40,761	$	5,317	$	161,224

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 $390.1 million and $380.5 million for the three months ended Sept. 30, 2004 and 2003, respectively. Revenues from external customers were $1,044.2 million and $909.4 million for the nine months ended Sept. 30, 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 Sept. 30,				Nine Months Ended Sept. 30,
(Millions of Dollars)	2004		2003		2004			2003
Net income	$	68.4	$	80.4	$	171.1		$	144.5
Other comprehensive income:
After-tax net unrealized gains on derivatives accounted for as hedges (see Note 6)	—		—		0.1			—
After-tax net realized gains on derivative transactions reclassified into earnings (see Note 6)	—		—		(0.1		)	—
Other comprehensive income	—		—		—			—
Comprehensive income	$	68.4	$	80.4	$	171.1		$	144.5

The accumulated comprehensive income in stockholder’s equity at Sept. 30, 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 Sept. 30,					Nine Months Ended Sept. 30,
(Millions of Dollars)	2004		2003			2004		2003
Net income	$	17.7	$	12.3		$	43.3	$	37.0
Other comprehensive income:
After-tax net unrealized losses on derivatives accounted for as hedges (see Note 6)	—		(1.1		)	—		(1.1		)
Other comprehensive loss	—		(1.1		)	—		(1.1		)
Comprehensive income	$	17.7	$	11.2		$	43.3	$	35.9

The accumulated comprehensive income in stockholder’s equity at Sept. 30, 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 Sept. 30,						Nine Months Ended Sept. 30,
(Millions of Dollars)	2004			2003			2004			2003
Net income	$	59.1		$	57.5		$	142.2		$	161.2
Other comprehensive income:
After-tax net unrealized gains on derivatives accounted for as hedges (see Note 6)	4.3			18.4			6.0			17.6
After-tax net realized gains on derivative transactions reclassified into earnings (see Note 6)	(5.1		)	(0.9		)	(7.6		)	(1.0		)
Unrealized gain on marketable securities	—			—			0.1			—
Other comprehensive income (loss)	(0.8		)	17.5			(1.5		)	16.6
Comprehensive income	$	58.3		$	75.0		$	140.7		$	177.8

The accumulated comprehensive income in stockholder’s equity at Sept. 30, 2004 and 2003, relates to valuation adjustments on PSCo’s derivative financial instruments and hedging activities and the mark-to-market component of PSCo’s marketable securities.

SPS

The components of total comprehensive income are shown below:

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
(Millions of Dollars)	2004			2003			2004		2003
Net income	$	28.8		$	38.1		$	63.6	$	67.1
Other comprehensive income:
After-tax net unrealized gains (losses) on derivatives accounted for as hedges (see Note 6)	(0.7		)	(0.8		)	0.9		(3.5		)
After-tax net realized losses on derivative transactions reclassified into earnings (see Note 6)	0.2			0.3			0.7		0.4
Minimum pension liability	—			—			—		(24.5		)
Other comprehensive income (loss)	(0.5		)	(0.5		)	1.6		(27.6		)
Comprehensive income	$	28.3		$	37.6		$	65.2	$	39.5

The accumulated comprehensive income in stockholder’s equity at Sept. 30, 2004 and 2003, relates to valuation adjustments on SPS’ derivative financial instruments and hedging activities and adjustments to its minimum pension liability.

9. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended Sept. 30,
	2004			2003			2004			2003
(Thousands of Dollars) Xcel Energy Inc.	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	14,143		$	16,867		$	1,525		$	1,475
Interest cost	41,349			42,688			13,151			13,107
Expected return on plan assets	(75,690		)	(80,514		)	(5,812		)	(5,547		)
Amortization of transition (asset) obligation	(2		)	(499		)	3,644			3,857
Amortization of prior service cost (credit)	7,503			7,062			(544		)	(384		)
Amortization of net (gain) loss	(3,688		)	(11,210		)	5,412			3,853
Net periodic benefit cost (credit)	(16,385		)	(25,606		)	17,376			16,361
Settlements and curtailments	(223		)	—			—			—
Costs not recognized due to the effects of regulation	10,480			12,938			—			—
Additional cost recognized due to the effects of regulation	—			—			973			973
Net benefit cost (credit) recognized for financial reporting	$	(6,128	)	$	(12,668	)	$	18,349		$	17,334
NSP-Minnesota
Net periodic benefit cost (credit)	$	(10,340	)	$	(13,681	)	$	4,004		$	4,224
Credits not recognized due to the effects of regulation	10,480			12,938			—			—
Net benefit cost (credit) recognized for financial reporting	$	140		$	(743	)	$	4,004		$	4,224
NSP-Wisconsin
Net benefit cost (credit) recognized for financial reporting	$	(1,306	)	$	(1,974	)	$	599		$	630
PSCo
Net periodic benefit cost (credit)	$	1,963		$	(1,182	)	$	10,448		$	9,287
Additional cost recognized due to the effects of regulation	—			—			973			973
Net benefit cost (credit) recognized for financial reporting	$	1,963		$	(1,182	)	$	11,421		$	10,260
SPS
Net benefit cost (credit) recognized for financial reporting	$	(2,801	)	$	(4,134	)	$	1,377		$	1,543

	Nine Months Ended Sept. 30,
	2004			2003				2004				2003
(Thousands of Dollars) Xcel Energy Inc.	Pension Benefits							Postretirement Health Care Benefits
Service cost	$	43,617		$		50,601		$		4,575			$	4,420
Interest cost	124,023			128,064				39,453					39,320
Expected return on plan assets	(227,222		)	(241,542			)	(17,438			)		(16,639		)
Amortization of transition (asset) obligation	(6		)	(1,497			)	10,934					11,570
Amortization of prior service cost (credit)	22,509			21,186				(1,634			)		(1,150		)
Amortization of net (gain) loss	(11,406		)	(33,630			)	16,238					11,558
Net periodic benefit cost (credit)	(48,485		)	(76,818			)	52,128					49,079
Settlements and curtailments	(926		)	1,309				—					(2,128		)
Costs not recognized due to the effects of regulation	29,225			38,483				—					—
Additional cost recognized due to the effects of regulation	—			—				2,918					2,911
Net benefit cost (credit) recognized for financial reporting	$	(20,186	)	$	(37,026		)	$	55,046				$	49,862
NSP-Minnesota
Net periodic benefit cost (credit)	$	(28,916	)	$	(40,682		)	$	11,952				$	12,673
Credits not recognized due to the effects of regulation	29,225			38,483				—					—
Net benefit cost (credit) recognized for financial reporting	$	309		$	(2,199		)	$	11,952				$	12,673
NSP-Wisconsin
Net benefit cost (credit) recognized for financial reporting	$	(4,349	)	$	(5,870		)	$	1,796				$	1,891
PSCo
Net periodic benefit cost (credit)	$	5,939		$	(3,546		)	$	31,343				$	27,860
Additional cost recognized due to the effects of regulation	—			—				2,918					2,911
Net benefit cost (credit) recognized for financial reporting	$	5,939		$	(3,546		)	$	34,261				$	30,771
SPS
Net benefit cost (credit) recognized for financial reporting	$	(8,383	)	$	(12,402		)	$	4,132				$	4,631

Employer Contributions

In August 2004, PSCo contributed approximately $9 million to its bargaining pension plan. Xcel Energy anticipates contributing $55 million during 2004 to fund its retiree medical and life insurance plans, of which $27 million has been contributed at Sept. 30, 2004.

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

Discussion of financial condition and liquidity for the Utility Subsidiaries 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 the 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;

• 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 FERC 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 natural 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 or additional competition in the markets served by the Utility Subsidiaries;

• 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;

• Risks associated with implementations of new technologies; 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 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 are mitigated in most jurisdictions due to cost-based rate regulation. At Sept. 30, 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 MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

NSP-Minnesota’s net income was approximately $171.1 million for the first nine months of 2004, compared with approximately $144.5 million for the first nine 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:

(Millions of Dollars)	Base Electric Utility			Short-term Wholesale			Electric Commodity Trading			Consolidated Total
Nine months ended Sept. 30, 2004
Electric utility revenue	$	1,819		$	124		$	—		$	1,943
Electric fuel and purchased power	(679		)	(46		)	—			(725		)
Electric trading revenue	—			—			101			101
Electric trading costs	—			—			(100		)	(100		)
Gross margin before operating expenses	$	1,140		$	78		$	1		$	1,219
Margin as a percentage of revenue	62.7		%	62.9		%	1.0		%	59.6		%
Nine months ended Sept. 30, 2003
Electric utility revenue	$	1,811		$	98		$	—		$	1,909
Electric fuel and purchased power	(631		)	(51		)	—			(682		)
Electric trading revenue	—			—			61			61
Electric trading costs	—			—			(51		)	(51		)
Gross margin before operating expenses	$	1,180		$	47		$	10		$	1,237
Margin as a percentage of revenue	65.2		%	48.0		%	16.4		%	62.8		%

The following summarizes the components of the changes in base electric revenue and base electric margin for the nine months ended Sept. 30:

Base Electric Revenue

(Millions of Dollars)	2004 vs. 2003
Sales growth (excluding weather impact)	$	14
Estimated impact of weather	(29		)
Fuel and purchased power cost recovery	29
Interchange agreement billing with NSP-Wisconsin	(17		)
Renewable development fund recovery	(8		)
Firm wholesale	4
Transmission	2
Other	13
Total base electric revenue increase	$	8

Base Electric Margin

(Millions of Dollars)	2004 vs. 2003
Sales growth (excluding weather impact)	$	11
Estimated impact of weather	(22		)
Renewable development fund recovery	(8		)
Interchange agreement non-fuel cost sharing with NSP-Wisconsin	(16		)
Purchased capacity costs	(3		)
Transmission and other	(2		)
Total base electric margin decrease	$	(40	)

which lowered the 2003 costs of NSP-Minnesota shared with NSP-Wisconsin. In addition, an adjustment, which reduced expenses charged to NSP-Wisconsin by NSP-Minnesota, of $6.2 million was recorded for 2004 year-to-date billings.

Short-term wholesale margins increased approximately $31 million for the first nine months of 2004 compared with the same period in 2003. The higher results reflect a number of market factors, including high market prices, additional resources available for sale and a pre-existing contract, which expired in the first quarter of 2004. A comparable contract was not in place in 2003.

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.

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2004			2003
Natural gas utility revenue	$	468		$	480
Cost of natural gas sold and transported	(356		)	(368		)
Natural gas utility margin	$	112		$	112

Weather-adjusted natural gas sales declined for the first nine months of 2004, compared with the same period in 2003, as customers reduced their usage to offset the impact of higher natural gas prices. The negative sales growth, purchased natural gas adjustment clause recovery and estimated impact of weather on firm sales volume reduced natural gas revenue. The following summarizes the components of the changes in natural gas revenue and margin for the nine months ended Sept. 30:

Natural Gas Revenue

(Millions of Dollars)	2004 vs 2003
Sales growth (excluding weather impact)	$	(3	)
Estimated impact of weather on firm sales volume	(5		)
Purchased natural gas adjustment clause recovery	(8		)
Off system sales	5
Transportation and other	(1		)
Total natural gas revenue decrease	$	(12	)

Natural Gas Margin

(Millions of Dollars)	2004 vs 2003
Estimated impact of weather on firm sales volume	$	(2	)
Off system sales	1
Transportation and other	1
Total natural gas margin increase (decrease)	$	—

Non-Fuel Operating Expense and Other Costs — The following summarizes the components of the changes in other operating and maintenance expense for the nine months ended Sept. 30:

(Millions of Dollars)	2004 vs 2003
Lower plant outage costs	$	(19.3	)
Lower private fuel storage costs	(4.6		)
Lower restricted stock unit grants related to the 2003 grant	(2.2		)
Conservation and demand-side management costs	(2.0		)
Higher bad debt costs	4.8
Lower pension credits and 2003 401(k) match true-up	4.5
Costs offset in revenue	2.9
Inventory adjustments	1.3
Property insurance	1.1
Other	1.8
Total other operating and maintenance expense decrease	$	(11.7	)

Depreciation and amortization expense decreased by approximately $37.5 million, or 13.2 percent, for the first nine months of 2004, compared with the first nine 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. As a result, a year-to-date adjustment was recorded in the fourth quarter of 2003, which reduced depreciation expense by $22 million. In addition, 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. The year-to-date reduction in depreciation and amortization reflects the impact on 2004 of the Prairie Island life extension. In addition, renewable development fund amortization decreased $10 million, primarily due to a June 2003 payment. These costs are largely recovered through NSP-Minnesota’s state fuel clause recovery mechanism.

Interest charges and financing costs decreased by approximately $5.5 million, or 5.4 percent, for the first nine months of 2004, compared with the first nine 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 NSP-Minnesota’s subsidiary trust.

Income tax expense increased by approximately $15.0 million for the first nine months of 2004, compared with the first nine months of 2003. The increase is primarily due to higher pretax income in 2004. The effective tax rate for NSP-Minnesota was 32.9 percent in the first nine months of 2004 and 32.3 percent in 2003. The nine months ended Sept. 30, 2004 effective rate is higher than in 2003 due to adjustments recorded in 2003 relating to state tax accruals and favorable income tax audit settlements.

NSP-WISCONSIN MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

NSP-Wisconsin’s net income was $43.3 million for the first nine months of 2004, compared with $37.0 million for the first nine 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.

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2004			2003
Electric utility revenue	$	355		$	358
Electric fuel and purchased power	(158		)	(175		)
Gross margin before operating expenses	$	197		$	183
Margin as a percentage of revenue	55.5		%	51.1		%

The following summarizes the components of the changes in base electric revenue and base electric margin for the nine months ended Sept. 30:

Base Electric Revenue

(Millions of Dollars)	2004 vs. 2003
Sales growth (excluding weather impact)	$	6
Estimated impact of weather	(5		)
Interchange agreement billing with NSP-Minnesota	(2		)
Other	(2		)
Total base electric revenue decrease	$	(3	)

Base Electric Margin

(Millions of Dollars)	2004 vs. 2003
Sales growth (excluding weather impact)	$	4
Estimated impact of weather	(3		)
Fuel cost recovery	(3		)
Interchange agreement non-fuel cost sharing with NSP-Minnesota	16
Renewable development fund recovery	2
Other	(2		)
Total base electric margin increase	$	14

As discussed in the Utility Subsidiaries’ Annual Reports on Form 10-K for the year ended Dec. 31, 2003, the electric production and transmission systems of NSP-Minnesota and NSP-Wisconsin are managed as an integrated system. An interchange agreement, approved by the FERC, provides for the sharing of all costs of generation and transmission facilities of the system. The sharing of system costs is subject to an annual true-up adjustment. In the third quarter of 2004, an adjustment of $9.8 million was recorded, which lowered the 2003 costs of NSP-Minnesota shared with NSP-Wisconsin. In addition, an adjustment, which reduced expenses charged to NSP-Wisconsin by NSP-Minnesota, of $6.2 million was recorded for 2004 year-to-date billings.

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.

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2004			2003
Natural gas utility revenue	$	88		$	90
Cost of natural gas purchased and transported	(67		)	(68		)
Natural gas utility margin	$	21		$	22

The following summarizes the components of the changes in natural gas revenue and margin for the nine months ended Sept. 30:

Natural Gas Revenue

(Millions of Dollars)	2004 vs. 2003
Estimated impact of weather on firm sales volume	(1		)
Purchased natural gas adjustment clause recovery	(1		)
Total natural gas revenue decrease	$	(2	)

Natural Gas Margin

(Millions of Dollars)	2004 vs. 2003
Estimated impact of weather on firm sales volume	(1		)
Total natural gas margin decrease	$	(1	)

Non-Fuel Operating Expense and Other Items

The following summarizes the components of the changes in other operating and maintenance expense for the nine months ended

Sept. 30:

(Millions of Dollars)	2004 vs. 2003
Higher legal settlement costs	$	0.9
Lower pension credits and 2003 401(k) match true-up	1.3
Meter credits relating to 2002 recorded in 2003	0.9
Higher interchange expense with NSP-Minnesota	1.1
Higher postage costs	1.0
Higher IT costs	1.0
Higher bad debt expense	1.0
Lower restricted stock unit grants related to the 2003 grant	(0.4		)
Other	0.2
Total other operating and maintenance expense increase	$	7.0

Other income (expense) for the first nine months of 2004 increased by approximately $0.4 million, or 41.3 percent, compared with the first nine months of 2003, largely due to higher allowance for funds used during construction.

Interest charges decreased by approximately $1.4 million, or 8.5 percent, for the first nine months of 2004 compared with the first nine months of 2003, primarily due to the long-term debt refinancing in October 2003 at a lower coupon rate.

Income tax expense increased by approximately $2.3 million in the first nine months of 2004 compared with the first nine months of 2003. The increase was primarily due to higher pretax income levels. The effective tax rate for NSP-Wisconsin was 38.8 percent for the first nine months of 2004 and 40.5 percent in 2003. The effective tax rate for the nine months ended Sept. 30, 2004 is lower than in 2003 due to the larger ratio of the equity component of allowance for funds used during construction to lower pretax income levels.

PSCo MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

PSCo’s net income was approximately $142.2 million for the first nine months of 2004, compared with approximately $161.2 million for the first nine 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. PSCo short-term wholesale margins and electric trading margins reflect the estimated impacts of regulatory sharing, if applicable, of certain margins with Colorado retail customers. 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:

(Millions of Dollars)	Base Electric Utility			Short-term Wholesale			Electric Commodity Trading			Consolidated Total
Nine months ended Sept. 30, 2004
Electric utility revenue	$	1,562		$	67		$	—		$	1,629
Electric fuel and purchased power	(875		)	(60		)	—			(935		)
Electric trading revenue	—			—			378			378
Electric trading costs	—			—			(378		)	(378		)
Gross margin before operating expenses	$	687		$	7		$	—		$	694
Margin as a percentage of revenue	44.0		%	10.4		%	—		%	34.6		%

Nine months ended Sept. 30, 2003
Electric utility revenue	$	1,535		$	40		$	—		$	1,575
Electric fuel and purchased power	(813		)	(43		)	—			(856		)
Electric trading revenue	—			—			191			191
Electric trading costs	—			—			(190		)	(190		)
Gross margin before operating expenses	$	722		$	(3	)	$	1		$	720
Margin as a percentage of revenue	47.0		%	(7.5%		)	0.5		%	40.8		%

The following summarizes the components of the changes in base electric revenue and base electric margin for the nine months ended Sept. 30:

Base Electric Revenue

(Millions of Dollars)	2004 vs. 2003
Sales growth (excluding weather impact)	$	17
Estimated impact of weather	(30		)
Fuel cost recovery	28
Firm wholesale	23
Quality service plan	(5		)
Transmission and other	(6		)
Total base electric revenue increase	$	27

Base Electric Margin

(Millions of Dollars)	2004 vs. 2003
Sales growth (excluding weather impact)	$	12
Estimated impact of weather	(23		)
Electric commodity adjustment incentive	8
Financial hedging costs	(4		)
Wheeling costs	(7		)
Retail jurisdictional allocation adjustment in 2003	(5		)
Purchased capacity and other costs	(14		)
Quality service plan	(5		)
Transmission and other	3
Total base electric margin decrease	$	(35	)

Natural Gas Utility Margins

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

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2004			2003
Natural gas utility revenue	$	672		$	529
Cost of natural gas sold and transported	(469		)	(311		)
Natural gas utility margin	$	203		$	218

The following summarizes the components of the changes in natural gas revenue and margin for the nine months ended Sept. 30:

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 natural gas adjustment clause recovery	159
Rate changes – Colorado	(15		)
Transportation and other	1
Total natural gas revenue increase	$	143

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	(15		)
Transportation and other	2
Total natural gas margin decrease	$	(15	)

Non-Fuel Operating Expense and Other Items

The following summarizes the components of the changes in other operating and maintenance expense for the nine months ended

Sept. 30:

(Millions of Dollars)	2004 vs. 2003
Lower pension credits and 2003 401(k) match true-up	$	9.5
Facility attachment and Florida storm costs offset in revenue	4.4
Higher medical and health care costs	4.3
Higher reliability costs	4.3
Higher bad debts costs	3.4
Higher plant outage related costs	2.5
Higher customer billing system conversion related call center costs	2.0
Lower restricted stock unit grants related to the 2003 grant	(2.0		)
Lower performance based compensation	(2.0		)
Inventory adjustments	(4.8		)
Other	(0.5		)
Total	$	21.1

Depreciation and Amortization Expense decreased by approximately $11.6 million, or 6.6 percent, for the first nine months of 2004 compared with the first nine 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 reduced annual depreciation expense by about $20 million. This action reduced 2003 depreciation expense by $10 million. PSCo’s depreciation expense in 2004 will reflect the full year impact of this change.

Interest and financing costs decreased by approximately $12.1 million, or 10.0 percent, for the first nine months of 2004 compared with the first nine 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 PSCo’s subsidiary trust.

Income tax expense decreased by approximately $19.0 million in the first nine months of 2004 compared with the first nine months of 2003. The decrease was primarily due to lower pretax income levels. The effective tax rate for PSCo was 27.7 percent for the first nine months of 2004 and 31.3 percent in 2003. The effective tax rate for the nine months ended Sept. 30, 2004 is lower than in 2003 due to the larger ratio of the equity component of allowance for funds used during construction to lower pretax income levels.

SPS MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

SPS’ net income was approximately $63.6 million for the first nine months of 2004, compared with approximately $67.1 million for the first nine 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.

(Millions of Dollars)	Base Electric Utility			Short-term Wholesale			Consolidated Total
Nine months ended Sept. 30, 2004
Electric utility revenue	$	1,041		$	3		$	1,044
Electric fuel and purchased power	(668		)	(2		)	(670		)
Gross margin before operating expenses	$	373		$	1		$	374
Margin as a percentage of revenue	35.8		%	33.3		%	35.8		%
Nine months ended Sept. 30, 2003
Electric utility revenue	$	904		$	5		$	909
Electric fuel and purchased power	(539		)	(4		)	(543		)
Gross margin before operating expenses	$	365		$	1		$	366
Margin as a percentage of revenue	40.4		%	20.0		%	40.3		%

Base Electric Revenue

(Millions of Dollars)	2004 vs. 2003
Sales growth (excluding weather impact)	$	9
Estimated impact of weather	(6		)
Capacity sales	1
Fuel cost recovery	136
Transmission and other	(3		)
Total base electric revenue increase	$	137

Base Electric Margin

(Millions of Dollars)	2004 vs. 2003
Sales growth (excluding weather impact)	$	7
Estimated impact of weather	(5		)
Capacity sales	1
Fuel cost settlement	5
Wheeling costs	7
Transmission and other	(7		)
Total base electric margin increase	$	8

Non-Fuel Operating Expense and Other Costs

The following summarizes the components of the changes in other operating and maintenance expense for the nine months ended

Sept. 30:

(Millions of Dollars)	2004 vs. 2003
Higher plant outage costs	$	2.6
Higher medical and health care costs	1.0
Lower pension credits and 2003 401(k) match true-up	2.8
Unfavorable inventory adjustment in 2003	(2.5		)
Higher legal settlement costs	2.3
Lower restricted stock unit grants related to the 2003 grant	(0.8		)
Other	1.7
Total other operating and maintenance expense increase	$	7.1

Taxes (other than income taxes) increased by approximately $3.1 million, or 8.8 percent, for the first nine months of 2004, compared with the first nine months of 2003. The increase is primarily due to higher franchise taxes and gross receipts taxes in Texas.

Income taxes decreased by approximately $2.4 million in the first nine months of 2004, compared with the first nine months of 2003. The decrease is primarily due to lower pre-tax income levels. The effective tax rate for SPS was 38.2 percent for the first nine months of 2004 and 38.3 percent for the first nine months of 2003.

Item 4. CONTROLS AND PROCEDURES

Disclosure 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 SEC rules and forms. As of Sept. 30, 2004, based on an evaluation carried out under the supervision and with the participation of management, including the chief executive officer (CEO) and the chief financial officer (CFO), of the effectiveness of our disclosure controls and the procedures, the CEO and CFO have concluded that Xcel Energy Utility Subsidiaries’ disclosure controls and procedures are effective.

Internal Controls Over Financial Reporting

No change in Xcel Energy 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, Xcel Energy Utility Subsidiaries’ internal control over financial reporting. Xcel Energy Utility Subsidiaries have made a number of changes in internal controls over financial reporting during the most recent fiscal quarter in order to make the control environment more effective and efficient.

Xcel Energy Utility Subsidiaries maintain internal control over financial reporting to provide reasonable assurance regarding reliability of financial reporting. Xcel Energy Utility Subsidiaries have evaluated and documented controls in process activities, in general computer activities, and on an entity-wide level. During the third quarter and in anticipation of issuing a report on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, Xcel Energy Utility Subsidiaries conducted testing and monitoring of internal controls over financial reporting. Based on the control evaluation, testing and remediation performed to date, we have not identified any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting

*		Incorporated by reference
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.

Northern States Power Co. (a Minnesota 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 and Chief Financial Officer