NORTHERN STATES POWER CO - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2003


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

		For the transition period from _______to________


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

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

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

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

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

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

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

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

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


Northern States Power Co. (a Minnesota Corporation)		Common Stock, $0.01 par value1,000,000 Shares

Northern States Power Co. (a Wisconsin Corporation)		Common Stock, $100 par value933,000 Shares

Public Service Co. of Colorado		Common Stock, $0.01 par value100 Shares

Southwestern Public Service Co.		Common Stock, $1 par value100 Shares

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION
	Item 1. Financial Statements
	Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
	Item 4. CONTROLS AND PROCEDURES
Part II. OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 6. Exhibits and Reports on Form 8-K
EX-4.01 Credit Agreement
EX-4.02 Credit Agreement
EX-4.03 Credit Agreement
EX-4.04 Credit Agreement
EX-31.01 Certification to Sec. 302 - NSP-Minnesota
EX-31.02 Certification to Sec. 302 - NSP-Wisconsin
EX-31.03 Certification to Sec. 302 - PSCo
EX-31.04 Certification to Sec. 302 - SPS
EX-32.01 Certification to Sec. 906 - NSP-Minnesota
EX-32.02 Certification to Sec. 906 - NSP-Wisconsin
EX-32.03 Certification to Sec. 906 - PSCo
EX-32.04 Certification to Sec. 906 - SPS
EX-99.01 Statement-Securities Litigation Reform

Table of Contents


PART I — FINANCIAL INFORMATION

Item 1. Item 2. Item 4.		Financial Statements Management’s Discussion and Analysis Controls and Procedures

PART II — OTHER INFORMATION

Item 1. Item 6.		Legal Proceedings Exhibits and Reports on Form 8-K

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

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

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

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

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


			Three Months Ended June 30,						Six Months Ended June 30,

			2003			2002			2003			2002

Operating revenues:
	Electric utility		$	571,638		$	563,918		$	1,158,549		$	1,101,800
	Natural gas utility			88,878			89,782			422,128			277,318
	Electric trading margin			2,001			(1,958	)		3,401			1,142
	Other			4,744			5,231			10,938			11,964

		Total operating revenues		667,261			656,973			1,595,016			1,392,224
Operating expenses:
	Electric fuel and purchased power			204,744			192,908			413,734			377,353
	Cost of natural gas sold and transported			62,770			59,390			331,462			187,878
	Other operating and maintenance expenses			211,979			188,228			423,589			410,102
	Depreciation and amortization			99,469			87,556			190,671			172,989
	Taxes (other than income taxes)			42,830			42,612			87,176			85,929
	Special charges (see Note 2)			—			—			—			4,324

		Total operating expenses		621,792			570,694			1,446,632			1,238,575

Operating income				45,469			86,279			148,384			153,649
Other income (expense):
	Interest income			1,493			5,451			3,393			6,920
	Other nonoperating income			5,554			2,170			8,154			10,457
	Nonoperating expense			(1,689	)		(1,725	)		(3,169	)		(2,817	)

		Total other income (expense)		5,358			5,896			8,378			14,560
Interest charges and financing costs:
	Interest charges — net of amounts capitalized (including financing costs of $2,246, $1,030, $3,980 and $2,189, respectively)			29,921			17,041			61,895			34,617
	Distributions on redeemable preferred securities of subsidiary trusts			3,937			3,938			7,875			7,875

		Total interest charges and financing costs		33,858			20,979			69,770			42,492
Income before income taxes				16,969			71,196			86,992			125,717
Income taxes (benefit)				(2,672	)		28,772			22,900			50,260

Net income			$	19,641		$	42,424		$	64,092		$	75,457

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

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


				Six Months Ended June 30,

				2003			2002

Operating activities:
	Net income			$	64,092		$	75,457
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			174,207			177,966
		Nuclear fuel amortization			21,870			24,586
		Deferred income taxes			(20,192	)		(30,725	)
		Amortization of investment tax credits			(3,683	)		(4,211	)
		Allowance for equity funds used during construction			(6,466	)		(3,423	)
		Gain on sale of property			—			(6,785	)
		Change in accounts receivable			(91	)		40,284
		Change in inventories			5,882			3,311
		Change in other current assets			20,274			21,789
		Change in accounts payable			(78,880	)		(33,825	)
		Change in other current liabilities			(94,746	)		(46,287	)
		Change in other noncurrent assets			2,160			(30,602	)
		Change in other noncurrent liabilities			29,842			50,879

			Net cash provided by operating activities		114,269			238,414
Investing activities:
	Capital/construction expenditures				(181,007	)		(201,216	)
	Allowance for equity funds used during construction				6,466			3,423
	Investments in external decommissioning fund				(25,769	)		(29,383	)
	Proceeds from sale of property				—			11,152
	Restricted cash				15,500			—
	Other investments — net				(2,536	)		(1,619	)

			Net cash used in investing activities		(187,346	)		(217,643	)
Financing activities:
	Short-term borrowings — net				115,000			37,997
	Repayment of long-term debt, including reacquisition premiums				(208,551	)		(778	)
	Capital contributions from parent				4,114			42,431
	Dividends paid to parent				(105,849	)		(92,679	)

			Net cash used in financing activities		(195,286	)		(13,029	)
Net (decrease) increase in cash and cash equivalents					(268,363	)		7,742
Cash and cash equivalents at beginning of period					310,338			17,169

Cash and cash equivalents at end of period				$	41,975		$	24,911

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

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


			June 30, 2003			December 31,
			(Unaudited)			2002

ASSETS
Current assets:
	Cash and cash equivalents		$	41,975		$	310,338
	Restricted cash			7,500			23,000
	Accounts receivable — net of allowance for bad debts of $7,261 and $5,812, respectively			231,603			231,996
	Accounts receivable from affiliates			25,257			24,773
	Accrued unbilled revenues			89,832			109,435
	Materials and supplies inventories — at average cost			106,503			106,037
	Fuel inventory — at average cost			36,689			34,875
	Natural gas inventory — at average cost			16,223			24,385
	Prepayments and other			36,892			38,065

		Total current assets		592,474			902,904

Property, plant and equipment, at cost:
	Electric utility plant			7,054,806			6,855,807
	Natural gas utility plant			725,441			716,844
	Construction work in progress			357,889			313,931
	Other			399,048			384,214

		Total property, plant and equipment		8,537,184			8,270,796
Less accumulated depreciation				(4,241,098	)		(4,624,988	)
Nuclear fuel — net of accumulated amortization: $1,080,401 and $1,058,531, respectively				97,298			74,139

		Net property, plant and equipment		4,393,384			3,719,947

Other assets:
	Nuclear decommissioning fund			688,522			617,048
	Other investments			24,339			22,730
	Regulatory assets			393,986			212,539
	Prepaid pension asset			290,714			263,713
	Other			63,837			72,144

		Total other assets		1,461,398			1,188,174

		Total assets	$	6,447,256		$	5,811,025

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

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


			June 30, 2003			December 31,
			(Unaudited)			2002

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	17,954		$	226,462
	Short-term debt			115,069			69
	Accounts payable			152,518			198,889
	Accounts payable to affiliates			34,357			66,866
	Taxes accrued			108,736			210,041
	Accrued interest			43,902			44,167
	Dividends payable to parent			53,332			52,280
	Other			50,074			43,255

		Total current liabilities		575,942			842,029

Deferred credits and other liabilities:
	Deferred income taxes			680,413			700,966
	Deferred investment tax credits			70,629			74,577
	Regulatory liabilities			558,154			486,035
	Benefit obligations and other			139,743			136,452
	Asset retirement obligations (see Note 1)			889,720			—

		Total deferred credits and other liabilities		2,338,659			1,398,030

Long-term debt				1,570,317			1,569,938
Mandatorily redeemable preferred securities of subsidiary trust				200,000			200,000
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares				10			10
Premium on common stock				817,983			813,869
Retained earnings				944,350			987,158
Accumulated other comprehensive income (loss)				(5	)		(9	)

		Total common stockholder’s equity		1,762,338			1,801,028

Commitments and contingencies (see Note 4)
		Total liabilities and equity	$	6,447,256		$	5,811,025

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

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


			Three Months Ended June 30,						Six Months Ended June 30,

			2003			2002			2003			2002

Operating revenues:
	Electric utility		$	108,048		$	110,189		$	228,574		$	227,111
	Natural gas utility			16,287			18,845			80,720			59,239
	Other			51			25			138			111

		Total operating revenues		124,386			129,059			309,432			286,461
Operating expenses:
	Electric fuel and purchased power			56,719			50,115			112,182			104,646
	Cost of natural gas sold and transported			10,978			13,523			61,634			42,757
	Other operating and maintenance expenses			27,632			25,303			52,070			48,891
	Depreciation and amortization			11,803			11,084			23,137			21,839
	Taxes (other than income taxes)			4,032			4,117			8,259			8,217
	Special charges (see Note 2)			—			—			—			512

		Total operating expenses		111,164			104,142			257,282			226,862

Operating income				13,222			24,917			52,150			59,599
Other income (expense):
Interest income				136			160			297			857
Other nonoperating income				346			94			608			275
Nonoperating expense				(104	)		(83	)		(206	)		(139	)

		Total other income (expense)		378			171			699			993
Interest charges — net of amounts capitalized (including financing costs of $224, $224, $448 and $448, respectively)				5,693			5,740			11,424			11,573

Income before income taxes				7,907			19,348			41,425			49,019
Income taxes				3,060			6,930			16,724			18,650

Net income			$	4,847		$	12,418		$	24,701		$	30,369

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

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


				Six Months Ended June 30,

				2003			2002

Operating activities:
	Net income			$	24,701		$	30,369
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			23,650			22,383
		Deferred income taxes			3,313			1,309
		Amortization of investment tax credits			(396	)		(403	)
		Allowance for equity funds used during construction			(548	)		(274	)
		Undistributed equity in earnings of unconsolidated affiliates			(43	)		(81	)
		Change in accounts receivable			9,894			213
		Change in inventories			1,413			2,363
		Change in other current assets			11,817			11,233
		Change in accounts payable			(5,433	)		4,611
		Change in other current liabilities			1,064			9,241
		Change in other noncurrent assets			(3,100	)		(6,748	)
		Change in other noncurrent liabilities			(127	)		1,210

			Net cash provided by operating activities		66,205			75,426
Investing activities:
	Capital/construction expenditures				(22,139	)		(17,270	)
	Allowance for equity funds used during construction				548			274
	Other investments — net				13			(275	)

			Net cash used in investing activities		(21,578	)		(17,271	)
Financing activities:
	Short-term borrowings (repayments) — net				(6,880	)		(34,300	)
	Capital contributions from parent				692			2,438
	Dividends paid to parent				(24,714	)		(22,425	)

			Net cash used in financing activities		(30,902	)		(54,287	)
Net increase in cash and cash equivalents					13,725			3,868
Cash and cash equivalents at beginning of period					98			30

Cash and cash equivalents at end of period				$	13,823		$	3,898

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

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


			June 30, 2003			December 31,
			(Unaudited)			2002

ASSETS
Current assets:
	Cash and cash equivalents		$	13,823		$	98
	Accounts receivable — net of allowance for bad debts of $1,145 and $1,373, respectively			37,790			47,890
	Accounts receivable from affiliates			1,666			1,460
	Accrued unbilled revenues			11,858			20,074
	Materials and supplies inventories — at average cost			6,565			5,994
	Fuel inventory — at average cost			4,313			6,006
	Natural gas inventory — at average cost			3,971			4,263
	Current deferred income taxes			6,097			—
	Prepaid taxes			13,299			13,735
	Prepayments and other			1,351			1,681

		Total current assets		100,733			101,201

Property, plant and equipment, at cost:
	Electric utility plant			1,175,546			1,161,901
	Natural gas utility plant			133,969			131,969
	Construction work in progress			25,861			18,305
	Other			93,719			95,631

		Total property, plant and equipment		1,429,095			1,407,806
Less accumulated depreciation				(614,462	)		(592,187	)

		Net property, plant and equipment		814,633			815,619

Other assets:
	Other investments			9,849			9,817
	Regulatory assets			47,259			48,112
	Prepaid pension asset			42,453			38,557
	Other			7,153			7,577

		Total other assets		106,714			104,063

		Total assets	$	1,022,080		$	1,020,883

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

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


			June 30, 2003		December 31,
			(Unaudited)		2002

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	40,034	$	40,034
	Short-term debt — notes payable to affiliate			—		6,880
	Accounts payable			13,898		23,535
	Accounts payable to affiliates			11,040		6,836
	Dividends payable to parent			12,683		12,260
	Other			21,271		20,225

		Total current liabilities		98,926		109,770

Deferred credits and other liabilities:
	Deferred income taxes			158,734		146,471
	Deferred investment tax credits			14,424		14,820
	Regulatory liabilities			11,860		11,950
	Benefit obligations and other			45,990		46,026

		Total deferred credits and other liabilities		231,008		219,267

Long-term debt				273,151		273,108
Common stock — authorized 1,000,000 shares of $100 par value; outstanding 933,000 shares				93,300		93,300
Premium on common stock				63,673		62,981
Retained earnings				262,022		262,457

		Total common stockholder’s equity		418,995		418,738
Commitments and contingencies (see Note 4)

		Total liabilities and equity	$	1,022,080	$	1,020,883

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

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


			Three Months Ended June 30,						Six Months Ended June 30,

			2003			2002			2003			2002

Operating revenues:
	Electric utility		$	492,734		$	451,880		$	987,223		$	889,529
	Natural gas utility			161,661			115,563			418,338			432,428
	Electric trading margin			2,062			1,283			11			(2,317	)
	Steam and other			4,722			5,213			11,370			12,978

		Total operating revenues		661,179			573,939			1,416,942			1,332,618
Operating expenses:
	Electric fuel and purchased power			274,922			196,775			530,717			405,943
	Cost of natural gas sold and transported			97,283			50,862			252,190			261,706
	Cost of sales — steam and other			2,729			2,275			6,427			3,800
	Other operating and maintenance expenses			115,972			105,460			230,740			222,778
	Depreciation and amortization			62,004			64,094			120,647			128,658
	Taxes (other than income taxes)			22,855			20,440			43,036			42,711
	Special charges (see Note 2)			—			—			—			131

		Total operating expenses		575,765			439,906			1,183,757			1,065,727

Operating income				85,414			134,033			233,185			266,891
Other income (expense):
Interest income				1,570			274			2,011			370
Other nonoperating income				4,321			2,851			5,883			4,130
Nonoperating expense				(4,213	)		(2,145	)		(7,417	)		(4,612	)

		Total other income (expense)		1,678			980			477			(112	)
Interest charges and financing costs:
	Interest charges — net of amounts capitalized (including financing costs of $2,199, $869, $3,915 and $1,738, respectively)			40,679			32,459			76,596			60,114
	Distributions on redeemable preferred securities of subsidiary trusts			3,686			3,572			7,372			7,372

		Total interest charges and financing costs		44,365			36,031			83,968			67,486
Income before income taxes				42,727			98,982			149,694			199,293
Income taxes				9,073			36,621			45,953			70,240

Net income			$	33,654		$	62,361		$	103,741		$	129,053

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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


				Six Months Ended June 30,

				2003			2002

Operating activities:
	Net income			$	103,741		$	129,053
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			125,550			133,089
		Deferred income taxes			63,515			23,103
		Amortization of investment tax credits			(3,666	)		(2,189	)
		Allowance for equity funds used during construction			(3,387	)		(21	)
		Change in accounts receivable			(16,068	)		38,128
		Change in unbilled revenue			70,310			103
		Change in recoverable natural gas and electric costs			(52,621	)		(75,615	)
		Change in inventories			43,713			6,162
		Change in other current assets			(24,643	)		(12,177	)
		Change in accounts payable			(49,448	)		(37,290	)
		Change in other current liabilities			(17,807	)		90,586
		Change in other noncurrent assets			(4,002	)		(16,734	)
		Change in other noncurrent liabilities			26,015			22,035

			Net cash provided by operating activities		261,202			298,233
Investing activities:
	Capital/construction expenditures				(175,390	)		(223,915	)
	Allowance for equity funds used during construction				3,387			21
	Proceeds from sale of property				4,114			13,547
	Other investments — net				(25,565	)		(6,207	)

			Net cash used in investing activities		(193,454	)		(216,554	)
Financing activities:
	Short-term borrowings (repayments) — net				410,804			(30,448	)
	Repayment of long-term debt, including reacquisition premiums				(596,819	)		(2,625	)
	Proceeds from the issue of long term debt				247,252			—
	Capital contributions from parent				1,490			54,749
	Dividends paid to parent				(119,396	)		(108,869	)

			Net cash used in financing activities		(56,669	)		(87,193	)
Net increase (decrease) in cash and cash equivalents					11,079			(5,514	)
Cash and cash equivalents at beginning of period					25,924			22,666

Cash and cash equivalents at end of period				$	37,003		$	17,152

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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


			June 30, 2003			December 31,
			(Unaudited)			2002

ASSETS
Current assets:
	Cash and cash equivalents		$	37,003		$	25,924
	Accounts receivable — net of allowance for bad debts of $14,754 and $13,685, respectively			191,757			165,743
	Accounts receivable from affiliates			9,462			19,407
	Accrued unbilled revenues			133,659			203,969
	Recoverable purchased natural gas and electric energy costs			101,782			23,131
	Materials and supplies inventories — at average cost			43,248			49,579
	Fuel inventory — at average cost			25,763			25,366
	Natural gas inventory — replacement cost in excess of LIFO: $38,658 and $20,502, respectively			47,899			85,679
	Prepayments and other			43,836			15,992

		Total current assets		634,409			614,790

Property, plant and equipment, at cost:
	Electric utility plant			5,495,854			5,345,464
	Natural gas utility plant			1,526,603			1,494,017
	Construction work in progress			425,008			456,800
	Other			622,675			624,764

		Total property, plant and equipment		8,070,140			7,921,045
Less accumulated depreciation				(2,992,974	)		(2,896,978	)

		Net property, plant and equipment		5,077,166			5,024,067

Other assets:
	Other investments			28,238			12,319
	Regulatory assets			233,133			238,600
	Other			36,882			35,150

		Total other assets		298,253			286,069

		Total assets	$	6,009,828		$	5,924,926

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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


			June 30, 2003			December 31,
			(Unaudited)			2002

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	177,114		$	282,097
	Short-term debt			500,000			88,074
	Note payable to affiliate			14,020			15,142
	Accounts payable			261,194			318,005
	Accounts payable to affiliates			47,741			40,449
	Taxes accrued			11,190			47,363
	Accrued interest			40,317			44,391
	Dividends payable to parent			59,269			60,550
	Current portion of deferred income tax			55,349			22,298
	Other			88,425			56,167

		Total current liabilities		1,254,619			974,536

Deferred credits and other liabilities:
	Deferred income taxes			577,933			553,006
	Deferred investment tax credits			72,971			74,987
	Regulatory liabilities			44,487			45,707
	Minimum pension liability			104,773			104,773
	Benefit obligations and other			78,356			74,335
	Customers advances for construction			172,586			142,992

		Total deferred credits and other liabilities		1,051,106			995,800

Long-term debt				1,739,538			1,782,128
Mandatorily redeemable preferred securities of subsidiary trust				—			194,000
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares				—			—
Premium on common stock				1,653,774			1,652,284
Retained earnings				416,623			430,997
Accumulated other comprehensive income (loss)				(105,832	)		(104,819	)

		Total common stockholder’s equity		1,964,565			1,978,462
Commitments and contingencies (see Note 4)

		Total liabilities and equity	$	6,009,828		$	5,924,926

See disclosures regarding PSCo in the Notes to Consolidated Financial Statements

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


			Three Months Ended June 30,						Six Months Ended June 30,

			2003			2002			2003			2002

Operating revenues			$	284,342		$	266,917		$	528,939		$	478,609
Operating expenses:
	Electric fuel and purchased power			170,416			158,399			310,604			256,375
	Other operating and maintenance expenses			38,186			38,370			81,030			77,886
	Depreciation and amortization			21,797			21,287			43,309			43,291
	Taxes (other than income taxes)			11,557			14,219			23,287			25,977
	Special charges (see Note 2)			—			—			—			5,321

		Total operating expenses		241,956			232,275			458,230			408,850

Operating income				42,386			34,642			70,709			69,759
Other income (expense):
Interest income				(215	)		76			923			791
Other nonoperating income				1,118			226			1,695			1,362
Nonoperating expense				(36	)		(51	)		(71	)		(54	)

		Total other income (expense)		867			251			2,547			2,099
Interest charges and financing costs:
	Interest charges — net of amounts capitalized (including financing costs of $1,790, $1,534, $3,429 and $3,069, respectively)			10,674			11,442			22,406			22,834
	Distributions on redeemable preferred securities of subsidiary trust			1,962			1,962			3,925			3,925

		Total interest charges and financing costs		12,636			13,404			26,331			26,759

Income before income taxes				30,617			21,489			46,925			45,099
Income taxes				11,720			8,060			17,937			16,922

Net income			$	18,897		$	13,429		$	28,988		$	28,177

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

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


				Six Months Ended June 30,

				2003			2002

Operating activities:
	Net income			$	28,988		$	28,177
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			46,860			51,397
		Deferred income taxes			10,800			300
		Amortization of investment tax credits			(125	)		(125	)
		Allowance for equity funds used during construction			(1,680	)		(496	)
		Change in recoverable electric energy costs			(25,646	)		—
		Change in accounts receivable			(4,346	)		(47,305	)
		Change in inventories			(1,932	)		(1,846	)
		Change in other current assets			(3,796	)		34,790
		Change in accounts payable			17,474			3,375
		Change in other current liabilities			(17,364	)		(46,083	)
		Change in other noncurrent assets			(9,846	)		(23,856	)
		Change in other noncurrent liabilities			3,683			22,527

			Net cash provided by operating activities		43,070			20,855
Investing activities:
	Capital/construction expenditures				(50,959	)		(19,023	)
	Allowance for equity funds used during construction				1,680			496
	Other investments — net				250			(2,937	)

			Net cash used in investing activities		(49,029	)		(21,464	)
Financing activities:
	Short-term borrowings — net				—			15,000
	Capital contributions from parent				1,391			615
	Dividends paid to parent				(49,077	)		(60,969	)

			Net cash used in financing activities		(47,686	)		(45,354	)
Net decrease in cash and cash equivalents					(53,645	)		(45,963	)
Cash and cash equivalents at beginning of period					60,700			65,499

Cash and cash equivalents at end of period				$	7,055		$	19,536

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

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


			June 30, 2003			December 31,
			(Unaudited)			2002

ASSETS
Current assets:
	Cash and cash equivalents		$	7,055		$	60,700
	Accounts receivable — net of allowance for bad debts of $1,985 and $1,559, respectively			53,505			49,460
	Accounts receivable from affiliates			23,088			22,787
	Accrued unbilled revenues			57,992			52,999
	Recoverable electric energy costs			42,085			16,439
	Materials and supplies inventories — at average cost			18,511			17,231
	Fuel inventory — at average cost			1,974			1,322
	Prepayments and other			4,862			6,059

		Total current assets		209,072			226,997

Property, plant and equipment, at cost:
	Electric utility plant			3,088,259			3,076,970
	Construction work in progress			89,864			64,908

		Total property, plant and equipment		3,178,123			3,141,878
	Less accumulated depreciation			(1,366,054	)		(1,338,340	)

		Net property, plant and equipment		1,812,069			1,803,538

Other assets:
	Other investments			14,132			14,382
	Intangible assets			40,063			—
	Regulatory assets			102,612			105,404
	Prepaid pension asset			55,843			105,044
	Other			9,194			9,979

		Total other assets		221,844			234,809

		Total assets	$	2,242,985		$	2,265,344

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

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


			June 30, 2003			December 31,
			(Unaudited)			2002

LIABILITIES AND EQUITY
Current liabilities:
	Accounts payable		$	89,429		$	73,536
	Accounts payable to affiliates			11,185			9,604
	Taxes accrued			6,104			24,107
	Accrued interest			7,634			7,630
	Dividends payable to parent			24,242			24,427
	Current portion of deferred income tax			18,878			13,034
	Other			24,479			23,649

		Total current liabilities		181,951			175,987

Deferred credits and other liabilities:
	Deferred income taxes			388,694			399,800
	Deferred investment tax credits			4,092			4,217
	Regulatory liabilities			2,292			2,363
	Derivative instrument valuation — at market			9,918			6,008
	Minimum pension liability			20,839			—
	Benefit obligations and other			26,280			22,597

		Total deferred credits and other liabilities		452,115			434,985

Long-term debt				725,806			725,662
Mandatorily redeemable preferred securities of subsidiary trust				100,000			100,000
Common stock — authorized 200 shares of $1.00 par value; outstanding 100 shares				—			—
Premium on common stock				412,720			411,329
Retained earnings				402,073			421,976
Accumulated other comprehensive income (loss)				(31,680	)		(4,595	)

		Total common stockholder’s equity		783,113			828,710
Commitments and contingencies (see Note 4)

		Total liabilities and equity	$	2,242,985		$	2,265,344

See disclosures regarding SPS in the Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS (collectively referred to as the Utility Subsidiaries of Xcel Energy) as of June 30, 2003, and Dec. 31, 2002; the results of their operations for the three and six months ended June 30, 2003 and 2002; and their cash flows for the six months ended June 30, 2003 and 2002. Due to the seasonality of electric and natural gas sales of Xcel Energy’s Utility Subsidiaries, interim results are not necessarily an appropriate base from which to project annual results.

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

Certain items in the 2002 income statements have been reclassified to conform to the presentation disclosed in the 2002 Annual Report on Form 10-K. These reclassifications had no effect on stockholder’s equity or net income as previously reported. The reclassifications were primarily to conform the presentation of all consolidated Xcel Energy subsidiaries to a standard corporate presentation.

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

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

NSP-Minnesota

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

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


	Increase (decrease) in:

	Plant			Regulatory			Long-Term
(Thousands of Dollars)	Assets			Assets			Liabilities

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

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

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


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

Steam plant retirement		$	2,725	$	—	$	—	$	66	$	—	$	2,791
Nuclear plant decommissioning			859,643		—		—		27,286		—		886,929

	Total liability	$	862,368	$	—	$	—	$	27,352	$	—	$	889,720

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

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

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

The fair value of the assets legally restricted for purposes of settling the nuclear asset retirement obligations is $835 million as of June 30, 2003.

NSP-Minnesota, NSP-Wisconsin, PSCo and SPS

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


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

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

Regulatory Recovery Adjustment (2002) — During the first quarter of 2002, SPS wrote off approximately $5 million, or 1 cent per share, of restructuring costs relating to costs incurred to comply with legislation requiring a transition to retail competition in Texas, which was subsequently amended to delay the required transition.

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

The following table summarizes the activity related to accrued restaffing special charges for the first six months of 2003:


			Dec. 31, 2002		Accrued					June 30, 2003
(Thousands of Dollars)			Liability*		Special Charges		Payments			Liability*

Employee severance and related costs for Utility Subsidiaries:
	NSP-Minnesota		$	1,567	$	—	$	(1,263	)	$	304
	NSP-Wisconsin			171		—		(132	)		39
	PSCo			267		—		(248	)		19
	SPS			250		—		(227	)		23

		Total accrued special charges	$	2,255	$	—	$	(1,870	)	$	385

Reported on the balance sheets in other current liabilities.

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

NSP-Minnesota Service Quality Investigation — As previously reported, the Minnesota Public Utilities Commission (MPUC) directed the Office of the Attorney General and the Department of Commerce (state agencies) to investigate the accuracy of NSP-Minnesota’s reliability records. On Aug. 4, 2003, the state agencies jointly filed with the MPUC a report issued by Fraudwise, an investigation firm. Fraudwise had previously been engaged by the state agencies to investigate the validity of allegations involving the integrity of NSP-Minnesota’s service quality reporting. The findings of the Aug. 4, 2003 report are generally consistent with the previously disclosed findings in Fraudwise’s preliminary report that our record keeping contains inconsistencies and misstatements and that it would be nearly impossible to establish the magnitude of misstatements in the record keeping system. The report also states that NSP-Minnesota’s records were unreliable and appear to have been manipulated by a small number of employees to ensure compliance with state-imposed standards. NSP-Minnesota is continuing its internal review of these matters and has taken certain remedial actions to address the record keeping deficiencies. The MPUC has indicated that it is reviewing the report and expects to have a hearing on the matters addressed in the report within two to four months.

The South Dakota Public Utilities Commission (SDPUC) recently indicated an intention to open an investigation into service quality issues. In particular, the investigation would focus on NSP-Minnesota operations in the Sioux Falls area, which has experienced a number of recent power outages. NSP-Minnesota is working with the SDPUC to provide information and to answer inquiries regarding service quality. No docket has been opened.

Midwest Independent Transmission System Operator, Inc. (MISO) Electric Market Initiative (NSP-Minnesota and NSP-Wisconsin) - On July 25, 2003, MISO filed proposed changes to its regional open access transmission tariff to implement a new transmission and energy markets tariff that would establish certain wholesale energy and transmission service markets based on locational marginal cost pricing (LMP) effective in 2004. NSP-Minnesota and NSP-Wisconsin presently receive transmission services from MISO for service to their retail loads and would be subject to the new tariff, if approved by the Federal Energy Regulatory Commission (FERC). Xcel Energy continues to review the filing, but believes the new tariff, if approved by the FERC, could have a material effect on wholesale power supply or transmission service costs to NSP-Minnesota and NSP-Wisconsin beginning in 2004.

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

FERC Investigation Against All Wholesale Electric Sellers/California Refund Proceedings (PSCo) On June 25, 2003, the FERC issued a series of orders addressing the California electricity markets. Two of these were show cause orders. In the first show cause order, the FERC found that 24 entities may have worked in concert through partnerships, alliances or other arrangements to engage in activities that constitute gaming and/or anomalous market behavior. The FERC initiated the proceedings against these 24 entities requiring that they show cause why their behavior did not constitute gaming and/or anomalous market behavior. PSCo was not named in this order. In a second show cause order, the FERC indicated that various California parties, including the California Independent System Operator (CAISO), have alleged that 43 entities individually engaged in one or more of seven specific types of practices that the FERC has identified as constituting gaming or anomalous market behavior within the meaning of the CAISO and California Power Exchange tariffs. PSCo was listed in an attachment to that show cause order as having been alleged to have engaged in one of the seven identified practices, namely circular scheduling. In the second show cause order, FERC required the CAISO to provide the named entities with “all of the specific

transaction data” for each of the seven practices. The CAISO provided that information on July 16, 2003. This data does not list PSCo as among the entities that allegedly engaged in circular scheduling. PSCo may have been named in the show cause order because of a trader telephone conversation transcript that PSCo had previously submitted to the FERC. This transcript was cited in witnesses testimony filed with FERC. The circular scheduling reference in the transcript was by a trader from another company discussing a transaction that did not involve PSCo. PSCo is preparing a motion to dismiss.

Pacific Northwest FERC Refund Proceeding (PSCo) On June 25, 2003, the FERC terminated the proceeding without refunds or ordering further proceedings.

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

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

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

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

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

In June 2003, the CPUC issued its initial written order approving the settlement agreement. The new rates were effective July 1, 2003. PSCo will now move to the phase II, rate design, portion of the case.

PSCo Fuel Adjustment Clause Proceedings - Certain wholesale electric sales customers of PSCo have filed complaints with the FERC alleging PSCo has been improperly collecting certain fuel and purchased energy costs through the wholesale fuel cost adjustment clause included in their rates. The FERC consolidated these complaints and set them for hearing and settlement judge procedures. In November 2002, the Chief Judge terminated settlement procedures after settlement was not reached. The complainants filed initial testimony in late April 2003 claiming the improper inclusion of fuel and purchased energy costs in the range of $40 million to $50 million related to the periods 1996 through 2002. PSCo submitted answer testimony in June 2003. The complainants filed rebuttal testimony on August 1, 2003, and current claims have been reduced, now estimated at approximately $30 million. PSCo believes its wholesale customers have not been improperly charged for these costs. The hearings at the FERC are scheduled to begin Aug. 14, 2003.

PSCo had a retail incentive cost adjustment (ICA) cost recovery mechanism in place for periods prior to calendar 2003, as disclosed in the 2002 Annual Report on Form 10-K. The CPUC conducted a proceeding to review and approve the incurred and recoverable 2001 costs under the ICA. In April 2003, the CPUC Staff and an intervenor filed testimony recommending disallowance of certain fuel and purchased energy costs, which, if granted, would result in a $30 million reduction in recoverable 2001 ICA costs. On July 10, 2003, a stipulation and settlement agreement was filed with the CPUC, which resolved all issues. Under the stipulation and settlement agreement, the recoverable costs for 2001 will be reduced by $1.6 million. The resulting impact on the reset of the allowed cost recovery and cost sharing under the ICA for 2002 was not significant. In addition, the stipulation and settlement agreement provides for a prospective rate design adjustment related to the maximum allowable natural gas hedging costs that will be a part of the electric commodity adjustment for 2004. Approval of the 2002 recoverable ICA costs will be conducted in a future proceeding.

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

PSCo Electric Department Earnings Test Proceedings — PSCo has filed its annual electric department earnings test reports for calendar 2001 and 2002. In both years, PSCo did not earn above its allowed authorized return on equity and, accordingly, has not recorded any refund obligations. In the 2001 proceeding, the Office of Consumer Counsel has proposed that the $10.9

million gain on the sale of the Boulder Hydroelectric Project be excluded from 2001 earnings and that possible refund of the gain be addressed in a separate proceeding. A final decision on both proceedings is pending.

PSCo Gas Cost Prudence Review As previously reported, in May 2002, the staff of the CPUC filed testimony in PSCo’s gas cost prudence review case, recommending $6.1 million in disallowances of gas costs for the July 2000 through June 2001 gas purchase year. Hearings were held before an administrative law judge in July 2002. On February 10, 2003, the judge issued a recommended decision rejecting the proposed disallowances and approving PSCo’s gas costs for the subject gas purchase year as prudently incurred. On June 6, 2003, the CPUC issued its order denying exceptions to the administrative law judge’s recommended decision. The CPUC upheld the finding that PSCo was prudent and reasonable in its handling of the Western Natural Gas default in January 2001.

PSCo Wholesale General Rate Case — On June 19, 2003, PSCo filed a wholesale electric rate case with the FERC, proposing to increase the annual electric sales rates charged to wholesale customers, other than Cheyenne Light Fuel & Power Co., a wholly owned subsidiary of Xcel Energy, by approximately $9 million. Several wholesale customers intervened protesting the proposed increase. On Aug. 1, 2003, PSCo submitted a revised filing correcting an error in the calculation of income tax costs. The revised filing requests an approximately $2 million annual increase with new rates effective in January 2004, subject to refund.

Home Builders Association of Metropolitan Denver (PSCo) — In February 2001, Home Builders Association of Metropolitan Denver (HBA) sought an award in the amount of $13.6 million for PSCo’s failure to update its extension policy construction allowances from 1996 to 2002 under its tariff. An administrative law judge had ruled in January 2002 that HBA’s claims were barred. The CPUC reversed that decision and remanded the case. On May 15, 2003, an administrative law judge issued a recommended decision. On the remanded issues, the judge determined the HBA is able to seek an award of reparations on behalf of its member homebuilders. However, the judge further determined the construction allowance applied by PSCo from 1996 through 2002 was neither excessive nor discriminatory, and that HBA failed to meet its burden to show that its method of calculating reparations for the period 1996 through 2002 is proper.

SPS Texas Fuel Reconciliation, Fuel Factor and Fuel Surcharge Applications - In June 2002, SPS filed an application for the Public Utility Commission of Texas (PUCT) to retrospectively review the operations of the utility’s electric generation and fuel management activities. In this application, SPS filed its reconciliation for electric generation and fuel management activities, totaling approximately $608 million, from January 2000 through December 2001. In May 2003, a stipulation was approved by the PUCT. The stipulation resolves all issues regarding SPS’ fuel costs and wholesale trading activities through December 2001. SPS will withdraw, without prejudice, its request to share in 10 percent of margins from certain wholesale non-firm sales. SPS will recover $1.1 million from Texas customers for the proposed sharing of wholesale non-firm sales margins. The parties agreed that SPS would reduce its December 2001 fuel under-recovery balances by $5.8 million. Including the withdrawal of proposed margin sharing of wholesale non-firm sales, the net impact to SPS’ deferred fuel expense, before tax, is a reduction of $4.7 million.

In May 2003, SPS proposed to increase its voltage-level fuel factors to reflect increased fuel costs since the time SPS’ current fuel factors were approved in March 2002. The proposed fuel factors are expected to increase Texas annual retail revenues by approximately $60.2 million.

SPS also reported to the PUCT that it has under-collected its fuel costs under the current Texas retail fixed fuel factors. In the same May 2003 application, SPS proposed to surcharge $13.2 million and related interest for fuel cost under-recoveries incurred through March 2003. In June 2003, the Administrative Law Judge approved the increased fuel factors on an interim basis subject to hearings and completion of the case. The increased fuel factors became effective in July 2003. In July 2003, a unanimous settlement was reached adopting the surcharge and providing for the implementation of an expedited procedure for revising the fixed fuel factors on a semi-annual basis. The surcharge will be collected from customers over an eight-month period. In August 2003, the PUCT approved the settlement and the new proposed fuel cost recovery process and the surcharge will become effective in September 2003.

In July 2003, SPS filed a second fuel cost surcharge factor application in Texas to recover an additional $26 million of fuel cost under-recoveries accrued during April through June 2003. SPS proposed to surcharge its retail customers in Texas over a 12-month period. This new surcharge case is pending before the Texas State Office of Administrative Hearings.

SPS New Mexico Fuel Reconciliation and Fuel Factor Applications — On May 27, 2003 a hearing examiner issued a recommended decision on SPS’s fuel proceeding approving SPS utilizing a monthly fuel factor. SPS had been utilizing an annual fuel factor, which had allowed significant under-collections. The decision denied the intervernors’ request that all margins from off-system sales be credited to ratepayers. SPS will be obligated to file its next New Mexico fuel case two years after the recommended decision is approved. The recommended decision is subject to approval by the New Mexico Public Regulatory Commission.

TRANSLink Transmission Co., LLC (TRANSLink) — In June 2003, the MPUC held a joint hearing on the TRANSLink application, filed in December 2002. At the hearing, the MPUC deferred any decision. Instead, the MPUC indicated NSP-

Minnesota could submit a supplemental or revised application to explain certain recent changes to the proposal and to respond to a number of issues and questions posed by the MPUC advisory staff. No MPUC order will be issued, and no decision has been made regarding when the revised NSP-Minnesota filing will be submitted to the MPUC.

In 2002, SPS filed for PUCT and New Mexico Public Regulatory Commission approval to transfer functional control of its electric transmission system to TRANSLink, of which SPS would be a participant. In March 2003, the Southwest Power Pool and the MISO cancelled their planned merger to form a large mid-continent regional transmission organization (RTO). This development materially impacted SPS’ applications in Texas and New Mexico. SPS has withdrawn its applications in those two states while it evaluates new RTO arrangements.

Xcel Energy is considering these developments, as well as the proceedings in process in other jurisdictions, to evaluate the possible role of TRANSLink in providing transmission service in the Xcel Energy system.

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

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

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

French Island (NSP-Wisconsin) — In June 2003, the Department of Justice lodged a consent decree settling the EPA’s claims against NSP-Wisconsin related to the French Island generating plant. The consent decree will become enforceable and, unless changed in response to comments received, NSP-Wisconsin will pay a penalty of $500,000. On Aug. 2, 2003, the comment period for the consent decree expired.

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

St Cloud Gas Explosion (NSP-Minnesota) — As discussed previously in the Form 10-K for the period ending Dec. 31, 2002, 25 lawsuits have been filed as a result of a Dec. 11, 1998 gas explosion that killed four persons (including two employees of NSP-Minnesota), injured several others and damaged numerous buildings. Most of the lawsuits name as defendants, NSP-Minnesota, Seren, Cable Constructors, Inc. (CCI) (the contractor that struck the marked gas line) and Sirti, an architectural/engineering firm hired by Seren for its St. Cloud cable installation project. Recently, the court granted the plaintiffs’ request to amend the complaint to seek punitive damages against Seren and CCI. Presently, plaintiffs are bringing a similar motion against NSP-Minnesota. NSP-Minnesota maintains that this motion is without merit. Oral arguments are tentatively scheduled to be presented to the court on Sept. 12, 2003

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

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

Other - 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, 2002, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference. Following are unresolved contingencies, which are material to the financial position of Xcel Energy’s Utility Subsidiaries:

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

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

NSP-Minnesota

Financing Activity - At June 30, 2003, NSP-Minnesota had approximately $115 million of short-term debt outstanding at a weighted average interest rate of 2.51 percent.

In April 2003, NSP-Minnesota amended an existing shelf registration statement with $415 million of available debt to allow for the issuance of secured debt, in addition to unsecured debt.

On July 31, 2003, NSP-Minnesota redeemed $200 million of 7.875 percent Trust Originated Preferred Securities of NSP Financing I, its wholly owned subsidiary. The redemption price for each security was its $25 principal amount plus a $0.1695 unpaid distribution. NSP-Minnesota initially funded this redemption with cash on hand, availability under its credit facility and a short-term loan from the Xcel Energy holding company.

On Aug. 8, 2003, NSP-Minnesota issued $200 million of 2.875 percent first mortgage bonds due 2006 and $175 million of 4.75 percent first mortgage bonds due 2010. These issuances replaced first mortgage bonds, which matured in March and April of 2003, and helped fund the redemption of $200 million of Trust Originated Preferred Securities on July 31, 2003, which was initially funded as described above.

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

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

• payment of dividends only from retained earnings; and

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

NSP-Wisconsin

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

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

• payment of dividends only from retained earnings.

PSCo

Financing Activity — In March 2003, PSCo issued $250 million of 4.875 percent first collateral trust bonds due 2013. The bonds were sold to qualified institutional buyers.

In April 2003, PSCo registered $500 million of additional debt securities to supplement the existing $300 million of already registered debt securities.

On June 30, 2003, PSCo redeemed its $145 million of 8.75 percent first mortgage bonds due March 1, 2022. The redemption price was 100 percent of the principal amount plus a 3.76 percent call premium and accrued interest.

On June 30, 2003, PSCo’s trust subsidiary PSCo Capital Trust I redeemed its $194 million of 7.60 percent Trust Originated Preferred Securities. The redemption price for each security was its $25 principal amount plus a $0.475 unpaid distribution.

The redemptions were temporarily funded from the $300 million short-term credit facility, the $350 million revolving credit facility, and cash on hand. PSCo expects to issue permanent financing of about $575 million during the third quarter of 2003.

On June 30, 2003, PSCo had $500 million of short-term debt outstanding. $200 million was outstanding under its Revolving Credit Facility at 2.01 percent and $300 million was outstanding under its Bridge Credit Facility at 2.64 percent.

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

• maintenance of a minimum equity ratio of 30 percent;

• payment of dividends only from retained earnings; and

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

SPS

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

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

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

• mandatorily redeemable equity instruments;

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

• forward contracts that require the issuer to purchase shares.

SFAS No. 150 must be applied immediately to instruments entered into or modified after May 31, 2003, and to all other instruments that exist beginning July 1, 2003. SPS has a special purpose subsidiary trust with outstanding mandatorily redeemable preferred securities of $100 million consolidated in SPS’ Consolidated Balance Sheets, which will be required to be classified as long-term debt as of July 1, 2003.

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

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

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


	Six Months Ended June 30, 2003

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

Balance at Jan. 1, 2003	$	0.0		$	0.0		$	1.0		$	(4.6	)
After-tax net unrealized losses related to derivatives accounted for as hedges		(1.2	)		(0.2	)		(3.7	)		(2.7	)
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		0.0			0.0			(0.2	)		0.1

Accumulated other comprehensive loss before regulatory deferrals		(1.2	)		(0.2	)		(2.9	)		(7.2	)
Regulatory deferral of costs to be recovered*		1.2			0.2			2.9			0.0

Accumulated other comprehensive income (loss) related to SFAS No. 133 — June 30, 2003	$	0.0		$	0.0		$	0.0		$	(7.2	)

In accordance with SFAS 71 — “Accounting for the Effects of Certain Types of Regulation,” certain costs/benefits have been deferred as they will be recovered in future periods from customers.


	Six Months Ended June 30, 2002

(Millions of Dollars)	NSP-Minnesota			PSCo			SPS

Balance at Jan. 1, 2002	$	0.1		$	(4.3	)	$	(4.4	)
After-tax net unrealized gains related to derivatives accounted for as hedges		0.6			9.0			0.9
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(0.3	)		(5.0	)		0.1

Accumulated other comprehensive income (loss) related to SFAS No. 133 — June 30, 2002	$	0.4		$	(0.3	)	$	(3.4	)

Cash Flow Hedges

Xcel Energy’s Utility Subsidiaries enter into derivative instruments to manage their exposure to changes in commodity prices. These derivative instruments take the form of fixed-price, floating-price or index sales, or purchases and options, such as puts, calls and swaps. 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 June 30, 2003, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS had various commodity-related contracts deemed as cash flow hedges extending through 2009. Amounts deferred in Other Comprehensive Income are recorded as the hedged purchase or sales transaction is completed. This could include the physical purchases or sales of electric energy or the use of natural gas to generate electric energy. As of June 30, 2003, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS had no gains or losses accumulated in Other Comprehensive Income that are expected to be recognized in earnings during the next 12 months as the hedged transaction occurs. However, due to the volatility of commodities markets, the value in Other Comprehensive Income will likely change prior to its recognition in earnings.

As required by SFAS No. 133, PSCo recorded gains of $0 and $0.9 million related to ineffectiveness on commodity cash flow hedges during the three months ended June 30, 2003 and 2002, respectively. PSCo recorded gains of $0 and $1.0 million related to ineffectiveness on commodity cash flow hedges during the six months ended June 30, 2003 and 2002, respectively.

SPS enters into interest rate swap instruments that effectively fix the interest payments on certain floating rate debt obligations. These derivative instruments are designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. SPS expects to reclassify into earnings through June 2004 net losses from Other Comprehensive Income of approximately $0.9 million.

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

Derivatives Not Qualifying for Hedge Accounting

NSP-Minnesota and PSCo have trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market basis in their respective Consolidated Statements of Operations. All derivative instruments are recorded at the amount of the gain or loss from the transaction within Operating Revenues on the Consolidated Statements of Operations.

Normal Purchases or Normal Sales

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

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

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

Pending Accounting Change

In April 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 149 — “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS No. 149). SFAS No. 149, which amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies the discussion around initial net investment, clarifies when a derivative contains a financing component and amends the definition of an underlying to conform it to language used in FASB Interpretation No. 45. In addition, SFAS No. 149 also incorporates certain implementation issues of a derivative implementation group. The provisions of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The guidance will be applied to hedging relationships on a prospective basis. The Utility Subsidiaries are currently assessing SFAS No. 149, but do not anticipate that it will have a material impact on consolidated results of operations, cash flows or financial position.

In June 2003, for purposes of determining the applicability of the normal purchases and normal sales scope exception, the FASB issued SFAS No. 133 Implementation Issue No. C20 as supplemental guidance to SFAS No. 133 Implementation Issue No. C11. The effective date of the Implementation guidance of Issue No. C20 is the first day for the first fiscal quarter beginning after July 10, 2003, which for Xcel Energy’s Utility Subsidiaries is the fourth quarter. The Utility Subsidiaries are currently in the process of reviewing and interpreting this guidance and do not currently anticipate any material adverse financial impact due to the implementation of Issue No. C20 guidance.

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

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

NSP-Minnesota


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

Three months ended June 30, 2003
Revenues from:
	External customers		$	573,481	$	87,205		$	4,744		$	665,430
	Internal customers			158		1,673			—			1,831

		Total revenue		573,639		88,878			4,744			667,261
Segment net income			$	23,704	$	(4,829	)	$	766		$	19,641
Three months ended June 30, 2002
Revenues from:
	External customers		$	561,828	$	90,076		$	5,231		$	657,135
	Internal customers			132		(294	)		—			(162	)

		Total revenue		561,960		89,782			5,231			656,973
Segment net income			$	41,247	$	2,076		$	(899	)	$	42,424
Six months ended June 30, 2003
Revenues from:
	External customers		$	1,161,603	$	419,648		$	10,938		$	1,592,189
	Internal customers			347		2,480			—			2,827

		Total revenue		1,161,950		422,128			10,938			1,595,016
Segment net income			$	48,543	$	12,988		$	2,561		$	64,092
Six months ended June 30, 2002
Revenues from:
	External customers		$	1,102,647	$	277,289		$	11,964		$	1,391,900
	Internal customers			295		29			—			324

		Total revenue		1,102,942		277,318			11,964			1,392,224
Segment net income			$	61,964	$	12,701		$	792		$	75,457

NSP-Wisconsin


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

Three months ended June 30, 2003
Revenues from:
	External customers		$	108,016	$	15,814		$	51		$	123,881
	Internal customers			32		473			—			505

		Total revenue		108,048		16,287			51			124,386
Segment net income			$	5,482	$	(583	)	$	(52	)	$	4,847
Three months ended June 30, 2002
Revenues from:
	External customers		$	110,148	$	18,240		$	25		$	128,413
	Internal customers			41		605			—			646

		Total revenue		110,189		18,845			25			129,059
Segment net income			$	13,043	$	(35	)	$	(590	)	$	12,418
Six months ended June 30, 2003
Revenues from:
	External customers		$	228,503	$	79,680		$	138		$	308,321
	Internal customers			71		1,040			—			1,111

		Total revenue		228,574		80,720			138			309,432
Segment net income			$	20,848	$	3,906		$	(53	)	$	24,701
Six months ended June 30, 2002
Revenues from:
	External customers		$	227,025	$	58,539		$	111		$	285,675
	Internal customers			86		700			—			786

		Total revenue		227,111		59,239			111			286,461
Segment net income			$	27,305	$	3,870		$	(806	)	$	30,369

PSCo


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

Three months ended June 30, 2003
Revenues from:
	External customers		$	494,721	$	161,646	$	4,722	$	661,089
	Internal customers			75		15		—		90

		Total revenue		494,796		161,661		4,722		661,179
Segment net income			$	21,268	$	8,951	$	3,435	$	33,654
Three months ended June 30, 2002
Revenues from:
	External customers		$	453,094	$	115,550	$	5,213	$	573,857
	Internal customers			69		13		—		82

		Total revenue		453,163		115,563		5,213		573,939
Segment net income			$	53,443	$	7,113	$	1,805	$	62,361
Six months ended June 30, 2003
Revenues from:
	External customers		$	987,091	$	418,311	$	11,370	$	1,416,772
	Internal customers			143		27		—		170

		Total revenue		987,234		418,338		11,370		1,416,942
Segment net income			$	56,982	$	41,617	$	5,142	$	103,741
Six months ended June 30, 2002
Revenues from:
	External customers		$	887,092	$	432,401	$	12,978	$	1,332,471
	Internal customers			120		27		—		147

		Total revenue		887,212		432,428		12,978		1,332,618
Segment net income			$	85,264	$	38,013	$	5,776	$	129,053

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

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 $284.3 million and $266.9 million for the three months ended June 30, 2003 and 2002, respectively. Revenues from external customers were $528.9 million and $478.6 million for the six months ended June 30, 2003 and 2002, respectively.

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

NSP-Minnesota

The components of total comprehensive income are shown below:


		Three Months Ended June 30,						Six Months Ended June 30,

(Millions of Dollars)		2003			2002			2003			2002

Net income		$	19.6		$	42.4		$	64.1		$	75.5
Other comprehensive income:
	After-tax net unrealized gains (losses) on derivatives accounted for as hedges (see Note 6)		(1.2	)		0.7			(1.2	)		0.6
	After-tax net realized (gains) losses on derivative transactions reclassified into earnings (see Note 6)		—			(0.1	)		—			(0.3	)
	Regulatory deferral of costs to be recovered		1.2			—			1.2			—

Other comprehensive income			—			0.6			—			0.3

Comprehensive income		$	19.6		$	43.0		$	64.1		$	75.8

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

NSP-Wisconsin

The components of total comprehensive income are shown below:


		Three Months Ended June 30,					Six Months Ended June 30,

(Millions of Dollars)		2003			2002		2003			2002

Net income		$	4.8		$	12.4	$	24.7		$	30.3
Other comprehensive income:
	After-tax net unrealized gains (losses) on derivatives accounted for as hedges (see Note 6)		(0.2	)		—		(0.2	)		—
	Regulatory deferral of costs to be recovered		0.2			—		0.2			—

Other comprehensive income			—			—		—			—

Comprehensive income		$	4.8		$	12.4	$	24.7		$	30.3

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

PSCo

The components of total comprehensive income are shown below:


		Three Months Ended June 30,						Six Months Ended June 30,

(Millions of Dollars)		2003			2002			2003			2002

Net income		$	33.7		$	62.4		$	103.7		$	129.1
Other comprehensive income:
	After-tax net unrealized gains (losses) on derivatives accounted for as hedges (see Note 6)		(4.9	)		0.3			(3.7	)		9.0
	After-tax net realized (gains) losses on derivative transactions reclassified into earnings (see Note 6)		(0.6	)		(4.2	)		(0.2	)		(5.0	)
	Regulatory deferral of costs to be recovered		2.9			—			2.9			—

Other comprehensive income (loss)			(2.6	)		(3.9	)		(1.0	)		4.0

Comprehensive income		$	31.1		$	58.5		$	102.7		$	133.1

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

SPS

The components of total comprehensive income are shown below:


		Three Months Ended June 30,						Six Months Ended June 30,

(Millions of Dollars)		2003			2002			2003			2002

Net income		$	18.9		$	13.4		$	29.0		$	28.2
Other comprehensive income:
	After-tax net unrealized gains (losses) on derivatives accounted for as hedges (see Note 6)		(3.1	)		1.2			(2.7	)		0.9
	After-tax net realized (gains) losses on derivative transactions reclassified into earnings (see Note 6)		0.1			(0.1	)		0.1			0.1
	Minimum pension liability		(24.8	)		—			(24.8	)		—

Other comprehensive income (loss)			(27.8	)		1.1			(27.4	)		1.0

Comprehensive income (loss)		$	(8.9	)	$	14.5		$	1.6		$	29.2

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

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

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

The legislation also requires specified levels of payments to various third parties during the remaining operating life of the Prairie Island plant. These payments include: $2.25 million per year to the Prairie Island Tribal Community beginning in 2004; 5 percent of NSP-Minnesota’s conservation program expenditures (estimated at $2 million per year) to the University of Minnesota for renewable energy research; and an increase in funding commitments to the previously-established Renewable Development Fund from $500,000 per installed cask per year to a total of $16 million per year beginning in 2003. The legislation also designated $10 million in one-time grants to the University of Minnesota for additional renewable energy research, which is to be funded from commitments already made to the Renewable Development Fund. Nearly all of the cost increases to NSP-Minnesota from these required payments and funding commitments are expected to be recoverable in customer rates, mainly through existing cost recovery mechanisms. Funding commitments to the Renewable Development Fund would terminate after the Prairie Island plant discontinues operation unless the MPUC determines that Xcel Energy failed to make a good faith effort to move the waste, in which case NSP-Minnesota would have to make payments in the amount of $7.5 million per year.

10. Pension Plan Change and Impacts (SPS)

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

quarter. The minimum pension liability adjustment also increased SPS’ noncurrent intangible assets by approximately $40 million due to the recording of unamortized prior service costs, and reduced its previously recorded prepaid pension assets accordingly.

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

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

Forward-Looking Information

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

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

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

• business conditions in the energy industry;

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

• unusual weather;

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

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

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

Financial Market Risks

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

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

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


	Period Ended		Change from
(Millions of Dollars)	June 30, 2003		March 31, 2003		VaR Limit		Average		High		Low

Electric Commodity Trading (1)	$	0.90	$	0.29	$	6.0	$	0.69	$	1.00	$	0.41

(1)

Comprises transactions for both NSP-Minnesota and PSCo.

Energy Trading and Hedging Activities

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

For the period ended June 30, 2003, these contracts, with the exception of transmission and natural gas transportation contracts, were marked to market in accordance with Emerging Issues Task Force (EITF) 02-3 and SFAS No. 133. Changes in fair value of energy trading contracts that do not qualify for hedge accounting treatment are recorded in income in the reporting period in which they occur.

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

Trading Contracts


	Futures/Forwards

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

NSP-Minnesota		1	$	(472	)	$	—	$	—	$	—	$	(472	)
		2		2,283			—		—		—		2,283
PSCo		1		(1,331	)		—		—		—		(1,331	)
		2		1,701			—		—		—		1,701

Total Futures/Forwards Fair Value			$	2,181		$	—	$	—	$	—	$	2,181

Hedge Contracts


	Futures/Forwards

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

NSP-Minnesota		2	$	(1,760	)	$	—	$	—	$	—	$	(1,760	)
NSP-Wisconsin		2		(304	)		—		—		—		(304	)
PSCo		1		1,047			—		—		—		1,047
		2		(9,230	)		—		—		—		(9,230	)

Total Futures/Forwards Fair Value			$	(10,247	)	$	—	$	—	$	—	$	(10,247	)


	Options

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

NSP-Minnesota		2	$	(200	)	$	—	$	—	$	—	$	(200	)
PSCo		2		(311	)		1,980						1,669

Total Futures/Forwards Fair Value			$	(511	)	$	1,980	$	—	$	—	$	1,469

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

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

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

NSP-MINNESOTA MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

NSP-Minnesota’s net income was approximately $64.1 million for the first six months of 2003, compared with approximately $75.5 million for the first six months of 2002.

Electric Utility and Commodity Trading Margins

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

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

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


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

Six months ended June 30, 2003
Electric utility revenue	$	1,094		$	65		$	—		$	1,159
Electric fuel and purchased power		(380	)		(34	)		—			(414	)
Electric trading revenue		—			—			28			28
Electric trading costs		—			—			(25	)		(25	)

Gross margin before operating expenses	$	714		$	31		$	3		$	748

Margin as a percentage of revenue		65.3	%		47.7	%		10.7	%		63.0	%
Six months ended June 30, 2002
Electric utility revenue	$	1,053		$	49		$	—		$	1,102
Electric fuel and purchased power		(343	)		(34	)		—			(377	)
Electric trading revenue		—			—			18			18
Electric trading costs		—			—			(17	)		(17	)

Gross margin before operating expenses	$	710		$	15		$	1		$	726

Margin as a percentage of revenue		67.4	%		30.6	%		5.6	%		64.8	%

Base electric utility revenues increased by $41 million, or 3.9 percent, in the first six months of 2003, compared with the same period in 2002. Base electric utility margins increased by $4 million, or 0.6 percent in the first six months of 2003 when

compared with the same period in 2002. The increase in revenues and margins reflects sales growth and the recovery in 2003 of increased electric fuel costs and of the 2003 $10-million renewable development fund payments (for which a corresponding charge to depreciation expense was recorded), through the fuel clause mechanism and interchange agreement with NSP-Wisconsin. These increases were offset by the impact of an electric rate reduction attributable to a Minnesota state property tax reduction and unfavorable weather.

Short-term wholesale margins increased in the first six months of 2003, compared with the first six months of 2002, primarily due to more favorable prices on electric sales to other utilities.

Natural Gas Utility Margins

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


	Six Months Ended June 30,

(Millions of Dollars)	2003			2002

Natural gas utility revenue	$	422		$	277
Cost of natural gas sold and transported		(331	)		(188	)

Natural gas utility margin	$	91		$	89

Natural gas revenue increased by approximately $145 million, or 52.3 percent, in the first six months of 2003, primarily due to increases in the cost of natural gas, which are largely passed on to customers through various rate adjustment clauses. Natural gas margin for the first six months of 2003 increased by $2 million, or 2.2 percent, compared with the first six months of 2002, primarily due to sales growth and favorable weather in 2003, partially offset by lower margins from transportation services.

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expense increased by approximately $13.5 million, or 3.3 percent, for the first six months of 2003, compared with the first six months of 2002, primarily due to higher incentive and other employee benefit costs and a planned refueling outage at the Monticello nuclear plant.

Depreciation and Amortization Expense increased by approximately $17.7 million, or 10.2 percent, for the first six months of 2003, compared with the first six months of 2002, primarily due to $10 million of renewable development fund costs, which are largely recovered through NSP-Minnesota’s fuel clause mechanism and the interchange agreement with NSP-Wisconsin. Also, depreciation increased due to plant additions, including computer software.

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

Other Income (Expense) — net decreased by $6.2 million, due primarily to a gain on the sale of property by a subsidiary of NSP-Minnesota, First Midwest Auto Park, in March 2002 and interest income of $4.2 million from a federal income tax settlement recorded in June 2002. These decreases from 2002 were partially offset by higher allowances for funds used during construction in 2003.

Interest charges and financing costs increased by approximately $27.3 million, or 78.8 percent, for the first six months of 2003, compared with the first six months of 2002. The increase is due to the issuance of long-term debt in July and August of 2002, as part of a financing plan to reduce the dependence on short-term debt.

Income tax expense decreased by approximately $27.4 million for the first six months of 2003, compared with the first six months of 2002. The effective tax rate for NSP-Minnesota was 26.3 percent in the first six months of 2003 and 40.0 percent in the same period of 2002. The change in the effective tax rate between years primarily reflects adjustments to 2002 and year-to-date 2003 state tax accruals recorded in 2003 related to updated income apportionment by state, a higher ratio of tax credits to lower income levels and NSP-Minnesota adjustments due to favorable income tax audit settlements in 2003.

NSP-WISCONSIN MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

NSP-Wisconsin’s net income was $24.7 million for the first six months of 2003, compared with $30.4 million for the first six months of 2002.

Electric Utility Margins

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


	Six Months Ended June 30,

(Millions of Dollars)	2003			2002

Total electric utility revenue	$	229		$	227
Electric fuel and purchased power		(112	)		(105	)

Total electric utility margin	$	117		$	122

Electric utility margin decreased by approximately $5 million, or 4.1 percent, in the first six months of 2003, compared with the first six months of 2002, primarily due to lower fuel cost recovery through rates and higher unit costs of fuel and purchased power in 2003. Sales growth, favorable weather in 2003, and higher billings to NSP-Minnesota for energy delivered and cost allocations partially offset the margin decreases.

Natural Gas Utility Margins

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


	Six Months Ended June 30,

(Millions of Dollars)	2003			2002

Natural gas revenue	$	81		$	59
Cost of natural gas sold and transported		(62	)		(43	)

Natural gas utility margin	$	19		$	16

Natural gas revenue for the first six months of 2003 increased by approximately $22 million, or 37.3 percent, compared with the first six months of 2002, primarily due to significant increases in the cost of natural gas, which is largely recovered through various purchased natural gas cost recovery mechanisms. Natural gas margin increased by approximately $3 million, or 18.8 percent, in the first six months of 2003 due to sales growth and more favorable weather conditions in 2003.

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expense for the first six months of 2003 increased by approximately $3.2 million, or 6.5 percent, compared with the first six months of 2002, primarily due to higher incentive and other benefit costs partially offset by lower transmission interchange charges from NSP-Minnesota.

Depreciation and Amortization Expense increased by approximately $1.3 million, or 5.9 percent, in the first six months of 2003, compared with the first six months of 2002, primarily due to capital additions to utility plant.

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

PSCo’s MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

PSCo’s net income was $103.7 million for the first six months of 2003, compared with $129.1 million for the first six months of 2002.

Electric Utility and Commodity Trading Margins

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

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

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


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

Six months ended June 30, 2003
Electric utility revenue	$	955		$	32		$	—		$	987
Electric fuel and purchased power		(497	)		(34	)		—			(531	)
Electric trading revenue		—			—			104			104
Electric trading costs		—			—			(104	)		(104	)

Gross margin before operating expenses	$	458		$	(2	)	$	—		$	456

Margin as a percentage of revenue		48.0	%		(6.3	)%		—	%		41.8	%
Six months ended June 30, 2002
Electric utility revenue	$	860		$	30		$	—		$	890
Electric fuel and purchased power		(375	)		(31	)		—			(406	)
Electric trading revenue		—			—			790			790
Electric trading costs		—			—			(792	)		(792	)

Gross margin before operating expenses	$	485		$	(1	)	$	(2	)	$	482

Margin as a percentage of revenue		56.4	%		(3.3	)%		(0.3	)%		28.7	%

Base electric utility revenues increased approximately $95 million, or 11.0 percent, in the first six months of 2003 compared with the first six months of 2002 due mainly to higher cost recovery levels under the IAC in 2003.

Base electric utility margin decreased by approximately $27 million, or 5.6 percent, in the first six months of 2003, compared with the first six months of 2002. The lower base electric margins reflect higher demand costs, which are not recoverable under the IAC, the positive impact of incentive cost adjustment mechanisms in 2002 and unfavorable weather in 2003. Sales growth and the implementation of an air-quality improvement rider for the recovery of investments and related costs to improve air quality in Colorado partially offset the margin decrease 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. 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.


	Six Months Ended June 30,

(Millions of Dollars)	2003			2002

Natural gas revenue	$	418		$	432
Cost of natural gas sold and transported		(252	)		(262	)

Natural gas utility margin	$	166		$	170

Natural gas revenue for the first six months of 2003 decreased by approximately $14 million, or 3.3 percent, compared with the first six months of 2002, largely due to lower revenues recognized for cost recovery levels approved under the GCA. Natural gas margin for the first six months of 2003 decreased by approximately $4 million, or 2.4 percent, compared with the first six months of 2002, primarily due to warmer winter weather, which is less favorable for natural gas sales. GCA recovery was lower in 2003 despite higher natural gas costs in 2003 compared to 2002. Costs not recovered currently are deferred to future periods when GCA recovery is provided.

Non-Fuel Operating Expense and Other Items

Other Operation and Maintenance for the six months ended June 30, 2003 increased by approximately $8.0 million, or 3.6 percent, compared to 2002 due to higher incentive and other employee benefit costs, partly offset by lower outage related costs and timing of expenses.

Depreciation and Amortization Expense decreased by approximately $8.0 million, or 6.2 percent, for the first six months of 2003 compared with the first six months of 2002, primarily due to decreased amortization of capitalized software and to depreciation of Arapahoe plant units 1and 2 ending at Dec. 31, 2002.

Interest expense increased by approximately $16.5 million, or 27.4 percent, for the first six months of 2003 compared with the first six months of 2002. Increased interest costs reflect higher debt levels in 2003 and higher interest rates on recent debt issues.

Income tax expensed decreased by $24.3 million for the first six months of 2003 compared with the same period in 2002. The effective tax rate for PSCo was 30.7 percent in the first six months of 2003 compared with 35.2 percent for the same period in 2002. The change in the effective tax rate between years is due primarily to a higher ratio of tax credits to lower income levels.

SPS’ MANAGEMENT’S DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

SPS’ net income was approximately $29.0 million for the first six months of 2003, compared with approximately $28.2 million for the first six months of 2002.

Electric Utility Margins

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


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

Six months ended June 30, 2003
Electric utility revenue	$	525		$	4		$	529
Electric fuel and purchased power		(308	)		(3	)		(311	)

Gross margin before operating expenses	$	217		$	1		$	218

Margin as a percentage of revenue		41.3	%		25.0	%		41.2	%


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

Six months ended June 30, 2002
Electric utility revenue	$	476		$	3		$	479
Electric fuel and purchased power		(253	)		(3	)		(256	)

Gross margin before operating expenses	$	223		$	—		$	223

Margin as a percentage of revenue		46.8	%		—	%		46.6	%

Base electric utility revenue increased by approximately $49 million, or 10.3 percent, for the first six months of 2003, compared with the first six months of 2002. Base electric utility margin decreased by approximately $6 million, or 2.7 percent, for the first six months of 2003, compared with the first six months of 2002. Base electric revenues increased primarily due to higher fuel and purchased power costs recovered through electric rates, partially offset by the unfavorable effects of lower average temperatures, and lower sharing of commodity trading margins with PSCo and NSP-Minnesota through the JOA. The decrease in base electric margin was primarily due to the effects of lower capacity sales, the settlement of the Texas fuel proceeding, the unfavorable effects of lower average temperatures and lower revenues shared through the JOA.

Non-Fuel Operating Expense and Other Costs

Other Operating and Maintenance Expense increased by approximately $3.1 million, or 4.0 percent, for the first six months of 2003, compared with the first six months of 2002. The increase is primarily due to higher incentive and other employee benefit costs partially offset by lower outage costs.

Taxes (other than income taxes) decreased by approximately $2.7 million, or 10.4 percent, for the first six months of 2003, compared with the first six months of 2002. The decrease is the result of a lower franchise tax rate assessed in Texas for 2003.

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

Item 4. CONTROLS AND PROCEDURES

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

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

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

Part II. OTHER INFORMATION

Item 1. Legal Proceedings
In the normal course of business, various lawsuits and claims have arisen against the Utility Subsidiaries of Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. See Notes 3 and 4 of the Financial Statements in this Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 of NSP-Minnesota’s, NSP-Wisconsin’s, PSCo’s and SPS’ 2002 Form 10-K for a description of certain legal proceedings presently pending. There are no new significant cases to report against the Utility Subsidiaries of Xcel Energy and there have been no notable changes in the previously reported proceedings, except as set forth below.

NSP-Minnesota

Under a 1996 data services agreement, SchlumbergerSema, Inc. (SLB) provides automated meter reading, distribution automation, and other data services to NSP-Minnesota. In September 2002, NSP-Minnesota issued written notice that SLB committed events of default under the agreement, including SLB’s nonpayment of approximately $7.4 million for distribution automation assets. In November 2002, SLB demanded arbitration and asserted various claims against NSP-Minnesota totaling $24 million for alleged breach of an expansion contract and a meter purchasing contract. On April 9, 2003, the parties attempted to mediate their dispute. The mediation was unsuccessful. On April 16, 2003, SLB filed a motion in the U.S. Bankruptcy Court in Delaware for an order that “any claim against SchlumberSema, Inc. arising from the alleged failure to sign the DA Transfer Agreement was cured, released, waived, and/or barred by this court’s order of May 4, 2000 approving the sale of CellNet Data System, Inc.’s assets to SLB.” On June 3, 2003, the Court denied SLB’s motion. On June 20, 2003, SLB filed a second motion before the U.S. Bankruptcy Court in Delaware requesting an order similar to that previously requested. On July 23, 2003, the Court denied SLB’s second motion. The parties are preparing for arbitration.

NSP-Wisconsin

On Sept. 25, 2000, NSP-Wisconsin was served with a complaint in Eau Claire County Circuit Court, Wisconsin, on behalf of Claron and Janice Stubrud. The complaint alleged that stray voltage from NSP-Wisconsin’s system harmed their dairy herd resulting in lost milk production, lost profits and income, property damage, and injury to their dairy herd. The complaint also alleged that NSP-Wisconsin acted willfully and wantonly, entitling plaintiffs to treble damages. The plaintiffs alleged farm damages of approximately $3.8 million, $2.7 million of which represents prejudgment interest. On March 28, 2003, the trial court granted partial summary judgment to NSP-Wisconsin and dismissed plaintiffs’ claims for strict products liability, trespass, treble damages, and prejudgment interest. Plaintiffs’ negligence and nuisance claims are expected to proceed to trial in Eau Claire County in November 2003.

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

SPS

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

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

The following Exhibits are filed with this report:


4.01		Credit Agreement dated May 16, 2003, among NSP-Minnesota, Wells Fargo Bank N.A., Bank One N.A. and other financial institutions.


4.02		Credit Agreement dated May 16, 2003 among PSCo, Wells Fargo N.A., Bank One N.A. and other financial institutions.

4.03		Credit Agreement dated Feb. 18, 2003 among SPS, BankOne, N.A. and other financial institutions.

4.04		Credit Agreement dated June 24, 2003 among PSCo, Key Bank N.A. and other financial institutions.

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

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

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

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

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

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

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

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

99.01		Statement pursuant to Private Securities Litigation Reform Act.

(b) Reports on Form 8-K

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

NSP-Minnesota

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

NORTHERN STATES POWER CO. (A MINNESOTA CORPORATION) SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on Aug. 14, 2003.


		Northern States Power Co. (a Minnesota corporation)

		(Registrant)

		/s/ DAVID E. RIPKA

		David E. Ripka Vice President and Controller

		/s/ RICHARD C. KELLY

		Richard C. Kelly Vice President and Chief Financial Officer

NORTHERN STATES POWER CO. (A WISCONSIN CORPORATION) SIGNATURES


		Northern States Power Co. (a Wisconsin corporation)

		(Registrant)

		/s/ DAVID E. RIPKA

		David E. Ripka Vice President and Controller

		/s/ RICHARD C. KELLY

		Richard C. Kelly Vice President and Chief Financial Officer

PUBLIC SERVICE CO. OF COLORADO SIGNATURES


		Public Service Co. of Colorado

		(Registrant)

		/s/ DAVID E. RIPKA

		David E. Ripka Vice President and Controller

		/s/ RICHARD C. KELLY

		Richard C. Kelly Vice President and Chief Financial Officer

SOUTHWESTERN PUBLIC SERVICE CO. SIGNATURES


		Southwestern Public Service Co.

		(Registrant)

		/s/ DAVID E. RIPKA

		David E. Ripka Vice President and Controller

		/s/ RICHARD C. KELLY

		Richard C. Kelly Vice President and Chief Financial Officer

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

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

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

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

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

	•		payment of dividends only from retained earnings; and

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

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

	•		payment of dividends only from retained earnings.

	•		maintenance of a minimum equity ratio of 30 percent;

	•		payment of dividends only from retained earnings; and

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

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

	•		mandatorily redeemable equity instruments;

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

	•		forward contracts that require the issuer to purchase shares.

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

	•		business conditions in the energy industry;

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

	•		unusual weather;

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

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

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