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 ~~March 31,~~June 30, 2004

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

For the transition period from to

Commission File Number: 1-3034

Xcel Energy Inc.

(Exact name of registrant as specified in its charter)


Minnesota		41-0448030

(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)


800 Nicollet Mall, Minneapolis, Minnesota		55402
~~Minnesota~~		~~55402~~
(Address of principal executive Offices)		(Zip Code)

Registrant’s telephone number, including area code(612) 330-5500

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).
~~[X]~~ [X] Yes [ ] No

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


Class		Outstanding at ~~April 30,~~July 20, 2004

Common Stock, $2.50 par value		~~399,288,854~~399,820,500 shares

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

Three Months Ended March 31,
(Thousands of Dollars, Except Per Share Data 2004
2003
Operating revenues:

Electric utility $ 1,469,424 $ 1,365,378
Natural gas utility 762,808 654,272
Electric trading margin 4,176 (1,034 )
Nonregulated and other 54,177 56,941

Total operating revenues 2,290,585 2,075,557
Operating expenses:

Electric fuel and purchased power – utility 678,693 592,151
Cost of natural gas sold and transported – utility 594,252 474,211
Cost of sales – nonregulated and other 28,554 34,370
Other operating and maintenance expenses – utility 393,645 377,502
Other operating and maintenance expenses – nonregulated 20,652 23,560
Depreciation and amortization 175,771 191,153
Taxes (other than income taxes) 84,895 80,700

Total operating expenses 1,976,462 1,773,647

Operating income
314,123 301,910
Interest and other income (expense), net (see Note 9) 7,462 (805 )
Interest charges and financing costs:

Interest charges – net of amounts capitalized (includes other financing costs of $7,426 and $6,249, respectively) 107,742 105,076
Distributions on redeemable preferred securities of subsidiary trusts — 9,586

Total interest charges and financing costs 107,742 114,662
Income from continuing operations before income taxes 213,843 186,443
Income taxes 69,545 60,477

Income from continuing operations 144,298 125,966
Income from discontinued operations, net of tax (see Note 2) 5,613 14,046

Net income 149,911 140,012
Dividend requirements on preferred stock 1,060 1,060

Earnings available to common shareholders $ 148,851 $ 138,952

Weighted average common shares outstanding (thousands):

Basic 398,583 398,714
Diluted 421,921 417,368
Earnings per share – basic:

Income from continuing operations $ 0.36 $ 0.31
Discontinued operations 0.01 0.04

Earnings per share – basic $ 0.37 $ 0.35

Earnings per share – diluted:

Income from continuing operations $ 0.35 $ 0.31
Discontinued operations 0.01 0.03

Earnings per share – diluted $ 0.36 $ 0.34

~~See Notes to Consolidated Financial Statements~~

~~XCEL ENERGY INC. AND SUBSIDIARIES~~

~~CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)~~

(Thousands of ~~Dollars)~~Dollars, Except Per Share Data)

Three Months Ended March 31,
2004
2003
Operating activities:

Net income $ 149,911 $ 140,012
Remove (income) loss from discontinued operations (5,613 ) (14,046 )
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization 184,827 198,227
Nuclear fuel amortization 11,596 11,791
Deferred income taxes (9,584 ) 49,622
Amortization of investment tax credits (3,055 ) (3,110 )
Allowance for equity funds used during construction (8,456 ) (3,060 )
Undistributed equity in earnings of unconsolidated affiliates (998 ) 6,165
Unrealized (gain) loss on derivative financial instruments 2,807 3,000
Change in accounts receivable (14,897 ) (145,633 )
Change in inventories 73,589 81,376
Change in other current assets 117,422 (63,404 )
Change in accounts payable (158,862 ) (21,497 )
Change in other current liabilities 61,242 111,058
Change in other noncurrent assets 34,360 5,871
Change in other noncurrent liabilities 30,525 6,244
Operating cash flows used in discontinued operations (77,034 ) (89,950 )

Net cash provided by operating activities 387,780 272,666
Investing activities:

Utility capital/construction expenditures (242,067 ) (199,803 )
Allowance for equity funds used during construction 8,456 3,060
Investments in external decommissioning fund (20,145 ) (8,406 )
Nonregulated capital expenditures and asset acquisitions (2,403 ) (5,636 )
Restricted cash 36,288 —
Other investments — net 887 (28,828 )
Investing cash flows provided by discontinued operations — 151,165

Net cash used in investing activities (218,984 ) (88,448 )
Financing activities

Short-term borrowings –net 32,000 (109,360 )
Proceeds from issuance of long-term debt — 247,277
Repayment of long-term debt, including reacquisition premiums (145,574 ) (110,811 )
Repurchase of stock (32,023 ) —
Dividends paid (75,867 ) (75,814 )
Financing cash flows used in discontinued operations (200 ) (24,588 )

Net cash used in financing activities (221,664 ) (73,296 )
Net (decrease) increase in cash and cash equivalents (52,868 ) 110,922
Net increase in cash and cash equivalents -discontinued operations 4,389 72,749
Net increase in cash and cash equivalents –adoption of FIN No.46 3,408 —
Cash and cash equivalents at beginning of year 571,761 484,578

Cash and cash equivalents at end of quarter $ 526,690 $ 668,249


	Three Months Ended June 30,					Six Months Ended June 30,
	2004		2003			2004		2003
Operating revenues:
Electric utility	$	1,476,234	$	1,374,327		$	2,945,658	$	2,739,705
Natural gas utility		273,365		266,741			1,036,173		921,013
Electric trading margin		942		5,648			5,118		4,614
Nonregulated and other		56,810		65,743			110,987		122,684

Total operating revenues		1,807,351		1,712,459			4,097,936		3,788,016
Operating expenses:
Electric fuel and purchased power – utility		723,022		639,342			1,401,715		1,231,493
Cost of natural gas sold and transported – utility		186,341		170,994			780,593		645,205
Cost of sales – nonregulated and other		30,168		39,952			58,722		74,322
Other operating and maintenance expenses – utility		392,890		378,520			786,535		756,022
Other operating and maintenance expenses – nonregulated		20,119		25,594			40,771		46,690
Depreciation and amortization		179,864		206,201			355,635		397,354
Taxes (other than income taxes)		82,596		81,355			167,491		162,055
Special charges		—		7,972			—		10,436

Total operating expenses		1,615,000		1,549,930			3,591,462		3,323,577

Operating income		192,351		162,529			506,474		464,439
Interest and other income – net of expense – net (see Note 9)		7,347		10,001			14,809		9,196
Interest charges and financing costs:
Interest charges – net of amounts capitalized (includes other financing costs of $7,006, $9,938, $14,432 and $16,187, respectively)		105,262		109,477			213,004		214,553
Distributions on redeemable preferred securities of subsidiary trusts		—		9,566			—		19,152

Total interest charges and financing costs		105,262		119,043			213,004		233,705
Income from continuing operations before income taxes		94,436		53,487			308,279		239,930
Income taxes (benefit)		13,259		(1,172	)		82,804		59,305

Income from continuing operations		81,177		54,659			225,475		180,625
Income (loss) from discontinued operations – net of tax (see Note 2)		5,129		(337,221	)		10,742		(323,175	)

Net income (loss)		86,306		(282,562	)		236,217		(142,550	)
Dividend requirements on preferred stock		1,060		1,060			2,120		2,120

Earnings (loss) available to common shareholders	$	85,246	$	(283,622	)	$	234,097	$	(144,670	)

Weighted average common shares outstanding (thousands):
Basic		399,217		398,717			398,900		398,716
Diluted		422,545		399,410			422,233		417,616
Earnings per share – basic:
Income from continuing operations	$	0.20	$	0.14		$	0.56	$	0.45
Income (loss) from discontinued operations		0.01		(0.85	)		0.03		(0.81	)

Earnings per share – basic	$	0.21	$	(0.71	)	$	0.59	$	(0.36	)

Earnings per share – diluted:
Income from continuing operations	$	0.20	$	0.13		$	0.54	$	0.44
Income (loss) from discontinued operations		0.01		(0.84	)		0.03		(0.77	)

Earnings per share – diluted	$	0.21	$	(0.71	)	$	0.57	$	(0.33	)

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED ~~BALANCE SHEETS~~STATEMENTS OF CASH FLOWS (UNAUDITED)
(Thousands of Dollars)

March 31, Dec. 31,
2004
2003
ASSETS

Current assets:
Cash and cash equivalents $ 526,690 $ 571,761
Restricted cash 150 37,363
Accounts receivable – net of allowance for bad debts of $30,417 and $30,899, respectively 665,504 650,808
Accrued unbilled revenues 300,693 367,005
Materials and supplies inventories – at average cost 168,177 167,199
Fuel inventory – at average cost 67,607 59,706
Natural gas inventories – at average cost as of March 31, 2004; replacement cost in excess of LIFO: $73,197 as of Dec. 31, 2003 (see Note 1) 90,880 140,636
Recoverable purchased natural gas and electric energy costs 161,992 217,473
Derivative instruments valuation – at market 60,533 62,537
Prepayments and other 108,411 142,241
Current assets held for sale and related to discontinued operations 235,597 714,510

Total current assets 2,386,234 3,131,239

Property, plant and equipment, at cost:
Electric utility plant 17,520,962 17,242,636
Natural gas utility plant 2,498,848 2,442,994
Nonregulated property and other 1,756,676 1,548,668
Construction work in progress 778,587 927,111

Total property, plant and equipment 22,555,073 22,161,409
Less accumulated depreciation (8,839,775 ) (8,667,358 )
Nuclear fuel – net of accumulated amortization: $1,113,528 and $1,101,932, respectively 71,505 80,289

Net property, plant and equipment 13,786,803 13,574,340

Other assets:
Investments in unconsolidated affiliates 73,119 124,462
Nuclear decommissioning fund and other investments 895,289 843,083
Regulatory assets 795,520 879,320
Derivative instruments valuation – at market 542,949 429,531
Prepaid pension asset 587,249 566,568
Other 193,537 208,465
Noncurrent assets held for sale and related discontinued operations 568,720 448,372

Total other assets 3,656,383 3,499,801

Total assets $ 19,829,420 $ 20,205,380


	Six Months Ended
	June 30,
	2004			2003
Operating activities:
Net income (loss)	$	236,217		$	(142,550	)
Remove (income) loss from discontinued operations		(10,742	)		323,175
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		369,045			390,652
Nuclear fuel amortization		22,948			21,870
Deferred income taxes		55,651			56,709
Amortization of investment tax credits		(6,111	)		(13,950	)
Allowance for equity funds used during construction		(16,684	)		(12,081	)
Undistributed equity in earnings of unconsolidated affiliates		104			4,503
Unrealized (gain) loss on derivative financial instruments		(6,310	)		6,049
Change in accounts receivable		27,631			(29,226	)
Change in inventories		56,099			53,033
Change in other current assets		29,148			(50,645	)
Change in accounts payable		(43,134	)		(242,573	)
Change in other current liabilities		(59,749	)		2,963
Change in other noncurrent assets		(5,791	)		(39,078	)
Change in other noncurrent liabilities		68,062			43,314
Operating cash flows used in discontinued operations		(380,560	)		202,325

Net cash provided by operating activities		335,824			574,490
Investing activities:
Utility capital/construction expenditures		(512,537	)		(423,508	)
Allowance for equity funds used during construction		16,684			12,081
Investments in external decommissioning fund		(40,289	)		(25,769	)
Nonregulated capital expenditures and asset acquisitions		(6,384	)		(12,655	)
Restricted cash		37,609			15,500
Other investments — net		(8,263	)		(37,998	)
Investing cash flows provided by discontinued operations		11,252			107,464

Net cash used in investing activities		(501,928	)		(364,885	)
Financing activities
Short-term borrowings – net		64,977			220,585
Proceeds from issuance of long-term debt		—			440,706
Repayment of long-term debt, including reacquisition premiums		(146,106	)		(801,933	)
Repurchase of stock		(32,023	)		—
Proceeds from issuance of common stock		—			218
Dividends paid		(151,860	)		(151,634	)
Financing cash flows used in discontinued operations		(200	)		(11,768	)

Net cash used in financing activities		(265,212	)		(303,826	)
Net decrease in cash and cash equivalents		(431,316	)		(94,221	)
Net decrease in cash and cash equivalents – discontinued operations		(24,283	)		(3,300	)
Net increase in cash and cash equivalents – adoption of FIN No.46		2,644			—
Cash and cash equivalents at beginning of year		571,761			484,578

Cash and cash equivalents at end of quarter	$	118,806		$	387,057

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	201,611		$	342,982
Cash paid for income taxes (net of refunds received)	$	(340,828	)	$	38,495

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(Thousands of Dollars)


	March 31,		Dec. 31,		June 30,			Dec. 31,
					2004			2003
ASSETS
Current assets:
Cash and cash equivalents					$	118,806		$	571,761
Restricted cash						150			37,363
Accounts receivable – net of allowance for bad debts of $31,662 and $30,899, respectively						623,538			650,808
Accrued unbilled revenues						366,144			367,005
Materials and supplies inventories – at average cost						169,960			167,199
Fuel inventory – at average cost						74,256			59,706
Natural gas inventories – at average cost as of June 30, 2004; replacement cost in excess of LIFO: $73,197 as of Dec. 31, 2003 (see Note 1)						99,938			140,636
Recoverable purchased natural gas and electric energy costs						158,188			217,473
Derivative instruments valuation – at market						57,028			62,537
Prepayments and other						125,447			142,241
Current assets held for sale and related to discontinued operations						226,552			714,510

Total current assets						2,020,007			3,131,239

Property, plant and equipment, at cost:
Electric utility plant						17,737,185			17,242,636
Natural gas utility plant						2,529,885			2,442,994
Nonregulated property and other						1,782,556			1,548,668
Construction work in progress						739,586			927,111

Total property, plant and equipment						22,789,212			22,161,409
Less accumulated depreciation						(8,976,015	)		(8,667,358	)
Nuclear fuel – net of accumulated amortization: $1,124,879 and $1,101,932, respectively						80,490			80,289

Net property, plant and equipment						13,893,687			13,574,340

Other assets:
Investments in unconsolidated affiliates						71,604			124,462
Nuclear decommissioning fund and other investments						912,273			843,083
Regulatory assets						875,560			879,320
Derivative instruments valuation – at market						628,353			429,531
Prepaid pension asset						605,950			566,568
Other						200,289			208,465
Noncurrent assets held for sale and related discontinued operations						528,490			448,372

Total other assets						3,822,519			3,499,801

Total assets					$	19,736,213		$	20,205,380
	2004		2003
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	10,757	$	159,955	$	11,071		$	159,955
Short-term debt		90,563		58,563		123,540			58,563
Accounts payable		629,584		785,580		745,532			785,580
Taxes accrued		292,573		189,088		191,319			189,088
Dividends payable		76,059		75,866		83,791			75,866
Derivative instruments valuation – at market		129,164		153,467		196,506			153,467
Other		319,609		416,455		317,080			416,455
Current liabilities held for sale and related to discontinued operations		388,156		832,092		25,043			832,092

Total current liabilities		1,936,465		2,671,066		1,693,882			2,671,066

Deferred credits and other liabilities:
Deferred income taxes		2,049,649		2,007,921		2,036,434			2,007,921
Deferred investment tax credits		152,471		155,629		149,313			155,629
Regulatory liabilities		1,614,645		1,559,779		1,694,746			1,559,779
Derivative instruments valuation – at market		436,051		388,743		477,920			388,743
Asset retirement obligations		1,040,778		1,024,529		1,057,285			1,024,529
Customer advances		218,634		211,046		224,255			211,046
Minimum pension liability		54,647		54,647		54,647			54,647
Benefit obligations and other		348,777		311,184		366,396			311,184
Noncurrent liabilities held for sale and related to discontinued operations		56,740		55,282		51,018			55,282

Total deferred credits and other liabilities		5,972,392		5,768,760		6,112,014			5,768,760

Minority interest in subsidiaries		689		281		4,192			281
Commitments and contingent liabilities (see Note 6)
Capitalization:
Long-term debt		6,577,397		6,493,853		6,563,447			6,493,853
Preferred stockholders’ equity – authorized 7,000,000 shares of $100 par value; outstanding shares:
1,049,800		104,980		104,980
Common stockholders’ equity – authorized 1,000,000,000 shares of $2.50 par value; outstanding shares: 2004 – 398,881,511; 2003 – 398,964,724		5,237,497		5,166,440
Preferred stockholders’ equity – authorized 7,000,000 shares of $100 par value; outstanding shares: 1,049,800						104,980			104,980
Common stockholders’ equity – authorized 1,000,000,000 shares of $2.50 par value; outstanding shares: 2004 – 399,395,315; 2003 - 398,964,724						5,257,698			5,166,440

Total liabilities and equity	$	19,829,420	$	20,205,380	$	19,736,213		$	20,205,380

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
AND OTHER COMPREHENSIVE INCOME
(UNAUDITED)
(Thousands)


	Common Stock Issued																		Common Stock Issued
													Accumulated																Accumulated
							Capital in			Retained			Other			Total							Capital in			Retained			Other			Total
	Number			Par			Excess of			Earnings			Comprehensive			Stockholders’			Number		Par		Excess of			Earnings			Comprehensive			Stockholders’
	of Shares			Value			Par Value			(Deficit)			Income (Loss)			Equity			of Shares		Value		Par Value			(Deficit)			Income (Loss)			Equity
Three months ended March 31, 2004 and 2003
Balance at Dec. 31, 2002		398,714		$	996,785		$	4,038,151		$	(100,942	)	$	(269,010	)	$	4,664,984
Three months ended June 30, 2004 and 2003
Balance at March 31, 2004																				398,882	$	997,204	$	3,887,900		$	442,514		$	(90,121	)	$	5,237,497
Net income											140,012						140,012										86,306						86,306
Currency translation adjustments														15,304			15,304													(6,575	)		(6,575	)
After-tax unrealized and realized losses related to derivatives -net (see Note 8)														(54,717	)		(54,717	)
After-tax unrealized and realized gains related to derivatives - net (see Note 8)																														15,529			15,529
Unrealized loss on marketable securities														(43	)		(43	)												(31	)		(31	)

Comprehensive income for the period																	100,556
Dividends declared:
Cumulative preferred stock of Xcel Energy											(1,060	)					(1,060	)

Balance at March 31, 2003		398,714		$	996,785		$	4,038,151		$	38,010		$	(308,466	)	$	4,764,480

Balance at Dec. 31, 2003		398,965		$	997,412		$	3,890,501		$	368,663		$	(90,136	)	$	5,166,440
Net income											149,911						149,911
Currency translation adjustments														5,394			5,394
After-tax unrealized and realized losses related to derivatives - net (see Note 8)														(5,502	)		(5,502	)
Unrealized gain on marketable securities														123			123

Comprehensive income for the period																	149,926																95,229
Dividends declared:
Cumulative preferred stock of Xcel Energy											(1,060	)					(1,060	)									(1,060	)					(1,060	)
Common stock											(75,000	)					(75,000	)									(82,665	)					(82,665	)
Issuances of common stock – net proceeds		1,717			4,292			24,922									29,214			513		1,284		7,413									8,697
Common stock repurchase		(1,800	)		(4,500	)		(27,523	)								(32,023	)

Balance at March 31, 2004		398,882		$	997,204		$	3,887,900		$	442,514		$	(90,121	)	$	5,237,497
Balance at June 30, 2004																				399,395	$	998,488	$	3,895,313		$	445,095		$	(81,198	)	$	5,257,698

Balance at March 31, 2003																				398,714	$	996,785	$	4,038,151		$	38,010		$	(308,466	)	$	4,764,480
Net loss																											(282,562	)					(282,562	)
Currency translation adjustment																														82,119			82,119
After-tax unrealized and realized losses related to derivatives - net (see Note 8)																														(5,932	)		(5,932	)
Minimum pension liability																														(24,838	)		(24,838	)
Unrealized gain on marketable securities																														53			53

Comprehensive loss for the period																																	(231,160	)
Dividends declared:
Cumulative preferred stock of Xcel Energy																								(1,060	)								(1,060	)
Common stock																								(148,461	)								(148,461	)
Issuances of common stock – net proceeds																				18		45		173									218

Balance at June 30, 2003																				398,732	$	996,830	$	3,888,803		$	(244,552	)	$	(257,064	)	$	4,384,017

XCEL ENERGY INC. AND SUBSIDIARIES

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 Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) as of ~~March 31,~~June 30, 2004, and Dec. 31, 2003; the results of its operations and stockholders’ equity for the three and six months ended ~~March 31,~~June 30, 2004 and 2003; and its cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003. Due to the seasonality of Xcel Energy’s electric and natural gas sales and variability of nonregulated operations, such interim results are not necessarily an appropriate base from which to project annual results.

The accounting policies followed by Xcel Energy are set forth in Note 1 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2003. The following notes should be read in conjunction with such policies and other disclosures in the Annual Report on Form 10-K.

1. Accounting Policies

FASB Interpretation No. 46 (FIN No. 46) —On Jan. 1, 2004, Xcel Energy adopted FIN No. 46, as revised, which requires an enterprise’s consolidated financial statements to include variable interest entities for which the enterprise is determined to be the primary beneficiary. Historically, consolidation has been required only for entities in which an enterprise has a majority voting or controlling interest. As a result, Xcel Energy consolidated a portion of its affordable housing investments made primarily through Eloigne, which were previously accounted for under the equity method. The consolidation had no impact on net income or earnings per share. No other arrangements were determined to be material variable interests requiring disclosure or consolidation under FIN No. 46.

As of ~~March 31,~~June 30, 2004, the assets of the affordable housing investments consolidated as a result of FIN No. 46, as revised, were approximately ~~$144~~$143 million and long-term liabilities were approximately ~~$78~~$77 million, including long-term debt of ~~$77~~$76 million. Investments of ~~$51~~$52 million, previously reflected as a component of investments in unconsolidated affiliates, have been consolidated with the entities’ assets initially recorded at their carrying amounts as of Jan. 1, 2004. The long-term debt is collateralized by the affordable housing projects and is nonrecourse to Xcel Energy.

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

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

Reclassifications– Certain items in the statements of operations and balance sheets have been reclassified from prior period presentation to conform to the 2004 presentation. These reclassifications had no effect on net income or earnings per share. The reclassifications were primarily related to organizational changes, such as the divestiture of NRG Energy, Inc. (NRG) and other discontinued operations.

2. Discontinued Operations

A summary of the subsidiaries presented as discontinued operations is discussed below. Results of operations as well as assets and liabilities for the divested businesses and the businesses held for sale are reported on a net basis as a component of discontinued operations for all periods presented. Amounts previously reported for 2003 have been restated to conform to the 2004 discontinued operations presentation.

Regulated Utility Segments

During 2004, Xcel Energy reached an agreement to sell its regulated electric and natural gas subsidiary, Cheyenne Light, Fuel and Power Company (CLF&P). As a result of this agreement, CLF&P is classified as held for sale. The sale is pending regulatory approval and is expected to be completed during 2004.

During 2003, Xcel Energy completed the sale of two subsidiaries in its regulated natural gas utility segment, Black Mountain Gas Co. (BMG) and Viking Gas Transmission Co. (Viking), including ~~its~~Viking’s interest in Guardian Pipeline, LLC. As a result, a gain of 5 cents per share was recorded in the first quarter of 2003, related to the sale of Viking. The BMG sale was completed in the third quarter of 2003.

NRG

Until December 2003, NRG was a wholly owned subsidiary of Xcel Energy. Prior to NRG’s bankruptcy filing in May 2003, Xcel Energy accounted for NRG as a consolidated subsidiary. However, as a result of NRG’s bankruptcy filing, Xcel Energy no longer had the ability to control the operations of NRG. Accordingly, effective as of the bankruptcy filing date, Xcel Energy ceased the consolidation of NRG and began accounting for its investment in NRG using the equity method in accordance with Accounting Principles Board Opinion No. 18 — “The Equity Method of Accounting for Investments in Common Stock.” In December 2003, NRG emerged from bankruptcy, and Xcel Energy relinquished its entire ownership interest in NRG. See additional discussion at Note 3.

Nonregulated Subsidiaries — All Other Segment

Xcel Energy International and e prime—During 2003, the board of directors of Xcel Energy approved management’s plan to exit businesses conducted by Xcel Energy International, Inc. (Xcel Energy International) and e ~~prime.~~prime, Inc. (e prime). Xcel Energy ~~International~~International’s operations primarily ~~includes~~include power generation projects in Argentina. e prime provided energy-related products and services, which included natural gas commodity trading and marketing and energy consulting. The assets held for sale are valued on an asset-by-asset basis at the lower of carrying amount or fair value less costs to sell. In applying those provisions, management considered cash flow analyses, bids and offers related to those assets and businesses. In accordance with the provisions of ~~SFAS~~Statements of Financial Accounting Standards (SFAS) No. 144 – “Accounting for the Impairment or Disposal of Long-Lived Assets”, assets held for sale will not be depreciated commencing with their classification as such.

The exit of all business conducted by e prime was completed in 2004. Xcel Energy ~~sold all of the contractual assets of e prime during the first quarter of 2004. During the first quarter of 2004, Xcel Energy closed~~also completed the sale of one of its Argentina subsidiaries, Hidroelectrica del Sur S.A. (HDS). The sale price of HDS was immaterial and approximated the book value of Xcel Energy’s investment in HDS.

On June 3, 2004, Xcel Energy Argentina Inc. (Xcel Argentina), a wholly owned subsidiary of Xcel Energy International, closed on the sale of the stock of Corporacion Independiente de Energia S.A. (CIESA), which has as its primary asset Central Piedra Buena S.A., a 620 megawatt gas/oil-fired facility in Bahia Blanca, Argentina to Bell Investments and Albanesi S.A. The sale also included the stock of IPC Operations Limited, an energy services company with operations in Buenos Aires, Argentina. The total purchase price was estimated at approximately $26 million, including certain adjustments subject to finalization in the third quarter. Approximately $15 million of the purchase price has been placed in escrow, which is expected to remain in place until the first quarter of 2005, to support Xcel Argentina’s customary indemnity obligations under the purchase agreement. In addition to the purchase price, Xcel Argentina also received approximately $21 million at closing as a redemption of its capital investment from CIESA. The sale resulted in an after-tax gain of $6.1 million, or approximately 1 cent per share, in the second quarter of 2004. The gain includes the realization of $6.9 million of tax benefits related to the now-realizable tax loss from disposition of Xcel Argentina assets.

Xcel Energy International is in the process of marketing its remaining assets and operations to prospective buyers and expects to exit the businesses held for sale during 2004.

Summarized Financial Results of Discontinued Operations

(Thousands of dollars)
Utility Segments
NRG Segment
All Other
Total
Three months ended March 31, 2004

Operating revenue $ 19,099 $ — $ 38,636 $ 57,735
Operating and other expenses 17,866 — 35,154 53,020
Other income — — 1,416 1,416

Pretax income from operations of discontinued components 1,233 — 4,898 6,131
Income tax expense 444 — 74 518

Net income from discontinued operations $ 789 $ — $ 4,824 $ 5,613

Three months ended March 31, 2003

Operating revenue and equity in project income $ 15,923 $ — $ 55,287 $ 71,210
Operating and other expenses 13,030 — 50,485 63,515
Equity in NRG losses — (11,609 ) — (11,609 )

Pretax income (loss) from operations of discontinued components 2,893 (11,609 ) 4,802 (3,914 )
Income tax expense 1,102 — 1,937 3,039

Income (loss) from operations of discontinued components 1,791 (11,609 ) 2,865 (6,953 )
Estimated pretax gain on disposal of discontinued components 35,799 — — 35,799
Income tax expense 14,800 — — 14,800

Gain on disposal of discontinued components 20,999 — — 20,999

Net income (loss) from discontinued operations $ 22,790 $ (11,609 ) $ 2,865 $ 14,046


(Thousands of dollars)	Utility Segments			NRG Segment			All Other			Total
Three months ended June 30, 2004
Operating revenue	$	26,144		$	—		$	7,855		$	33,999
Operating and other expenses		(25,216	)		—			(5,699	)		(30,915	)
Other expense		—			—			(887	)		(887	)

Pretax income from operations of discontinued components		928			—			1,269			2,197
Income tax benefit (expense)		(283	)		—			3,215			2,932

Net income from discontinued operations	$	645		$	—		$	4,484		$	5,129

Three months ended June 30, 2003
Operating revenue	$	11,483		$	—		$	46,889		$	58,372
Operating and other expenses		(10,693	)		—			(44,261	)		(54,954	)
Equity in NRG losses		—			(350,552	)		—			(350,552	)

Pretax income (loss) from operations of discontinued components		790			(350,552	)		2,628			(347,134	)
Income tax benefit (expense)		(294	)		—			10,207			9,913

Net income (loss) from discontinued operations	$	496		$	(350,552	)	$	12,835		$	(337,221	)


(Thousands of dollars)	Utility Segments			NRG Segment			All Other			Total
Six months ended June 30, 2004
Operating revenue	$	45,243		$	—		$	46,491		$	91,734
Operating and other expenses		(43,082	)		—			(40,853	)		(83,935	)
Other income		—			—			529			529

Pretax income from operations of discontinued components		2,161			—			6,167			8,328
Income tax benefit (expense)		(727	)		—			3,141			2,414

Net income from discontinued operations	$	1,434		$	—		$	9,308		$	10,742

Six months ended June 30, 2003
Operating revenue	$	27,406		$	—		$	102,176		$	129,582
Operating and other expenses		(23,723	)		—			(94,746	)		(118,469	)
Equity in NRG losses		—			(362,161	)		—			(362,161	)

Pretax income (loss) from operations of discontinued components		3,683			(362,161	)		7,430			(351,048	)
Income tax benefit (expense)		(1,396	)		—			8,270			6,874

Income (loss) from operations of discontinued components		2,287			(362,161	)		15,700			(344,174	)
Estimated pretax gain on disposal of discontinued components		35,799			—			—			35,799
Income tax expense		(14,800	)		—			—			(14,800	)

Gain on disposal of discontinued components		20,999			—			—			20,999

Net income (loss) from discontinued operations	$	23,286		$	(362,161	)	$	15,700		$	(323,175	)

910

In May 2003, NRG filed for bankruptcy to restructure its debt. At the time of the filing, NRG was a subsidiary of Xcel Energy. NRG’s filing included its plan of reorganization and a settlement among NRG, Xcel Energy and members of NRG’s major creditor constituencies.

In December 2003, NRG emerged from bankruptcy. As part of the reorganization, Xcel Energy completely relinquished its ownership interest in NRG. As part of the overall settlement, Xcel Energy agreed to pay $752 million to NRG to settle all claims of NRG against Xcel Energy, and claims of NRG creditors against Xcel Energy. In return for such payments, Xcel Energy received, or was granted, voluntary and involuntary releases from NRG and its creditors.

On Feb. 20, 2004, Xcel Energy paid $400 million to NRG. On April 30, 2004, Xcel Energy paid $328.5 million. The remaining $23.5 million ~~of the remaining $352 million, based~~payment was paid on ~~tax refunds received by~~May 28, 2004. Xcel Energy ~~in March 2004 from the carry back of its 2003 net operating loss that resulted from the write-off of its investment in NRG. Xcel Energy has~~ met these cash requirements with cash on hand, including ~~the~~ tax refund proceeds associated with the NRG bankruptcy, and/or borrowings under its revolving credit facility. ~~The remaining $23.5 million payment is due on May 30, 2004.~~

PSCo’s wholly owned subsidiary, PSR Investments, Inc. (PSRI), owns and manages permanent life insurance policies on some of ~~PSCo~~PSCo’s employees, known as corporate-owned life insurance (COLI). At various times, borrowings have been made against the cash values of these COLI policies and deductions taken on the interest expense on these borrowings. The IRS has challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through ~~1997.~~1999.

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

operations. Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding.

The total disallowance of interest expense deductions for the period of 1993 through ~~1997,~~1999, as proposed by the IRS, is approximately ~~$175~~$279 million. Additional interest expense deductions for the period ~~1998~~2000 through 2003 are estimated to total approximately ~~$404~~$300 million. Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2003, would reduce earnings by an estimated $254 million after tax. At June 30, 2004, Xcel Energy estimates its annual earnings for 2004 would be reduced by an estimated $35 million, after tax, which represents 8 cents per share using 2003 share levels, if COLI interest expense deductions were no longer available.

5. Rates and Regulation

Market Based Rate Authority Rule Proposal– On April 14, 2004, the Federal Energy Regulatory Commission (FERC) initiated a new ~~rulemaking~~proceeding on future market-based rates authorizations and issued interim requirements for FERC jurisdictional electric utilities that have been granted authority to make wholesale sales at market-based rates. NSP-Minnesota, NSP-Wisconsin, PSCo and Southwestern Public Service Company (SPS) currently have wholesale market-based rate authorization from the FERC. The FERC adopted a new interim method to assess generation market power and modified measures to mitigate market power where it is found. The FERC recently upheld and clarified the interim requirements on rehearing in an order issued July 8, 2004. The assessments will be made of all initial market-based rate applications and triennial reviews on an interim basis. ~~The Xcel Energy regulated subsidiaries’ triennial review is pending.~~ An assessment will be made of whether the utility is a pivotal supplier based on a control area’s annual peak demand orand whether it complies with market share requirements on a seasonal basis. If an applicant is determined to have generation market power, the applicant has the opportunity to propose its own mitigation plan or may implement default mitigation established by the FERC. The default mitigation limits prices for sales of power to cost-based rates within areas where an applicant is found to have market power. Xcel Energy is reviewing the new interim requirements to determine what, if any, impact ~~the new requirements~~they will have on the wholesale market-based rate authority of the utility subsidiaries. Xcel Energy is required to file an updated market power analysis using the new interim market power screens on or before Feb. 7, 2005. As a related matter, in addition to the triennial update filing, PSCo and SPS were required by the FERC, in its orders addressing the merger to form New Century Energies, Inc. in 1997, to file a supplemental market power analysis six months prior to the completion of the intertie transmission line between their systems to address the competitive impacts of that project. PSCo and SPS filed the required supplemental analysis on July 20, 2004.

Department of Energy Blackout Report– On April 6, 2004, the U.S. Department of Energy issued its final report regarding the Aug. 14, 2003 electric blackout in the eastern United States, which did not affect the electric systems of the Xcel Energy regulated utilities. The report recommends 4746 specific changes to current statutes, rules or practices in order to improve the reliability of the infrastructure used to transmit electric power. The recommendations include the establishment of mandatory reliability standards and financial penalties for noncompliance. On April 14, 2004, FERC issued a policy statement requiring electric utilities, including the Xcel Energy utility subsidiaries, to submit a report on vegetation management practices and indicating the FERC’s intent to make North American Electric Reliability Council (NERC) reliability standards mandatory. The Xcel Energy ~~is reviewing~~utility subsidiaries submitted the ~~final~~required report ~~and~~on their vegetation management practices to the FERC ~~policy statement.~~in June 2004. Implementation of the blackout report recommendations and the FERC policy statement could increase future transmission costs, but the extent of this effect cannot be determined at this time.

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

Midwest ISO Transmission and Energy Markets Tariff– On March 31, 2004, the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) regional transmission organization filed its proposed transmission and energy markets tariff (TEMT), which would establish regional wholesale energy markets using locational marginal cost pricing and financial transmission rights. NSP-Minnesota and NSP-Wisconsin are Midwest ISO members, and their generation plants and transmission systems would operate subject to the tariff if it is approved by the FERC. The Midwest ISO proposed a Dec. 1, 2004 effective date. ~~Comments~~

On May 26, 2004, the FERC issued an initial procedural order regarding the ~~tariff must~~TEMT. The FERC found that certain pre-Order 888 “grandfathered” agreements (GFAs) for transmission service could negatively affect implementation of the TEMT, so FERC delayed the effective date of the energy market to March 1, 2005. FERC also set the issue of the GFAs for an expedited hearing process. NSP-Minnesota and NSP-Wisconsin submitted compliance filings regarding their approximately 50 GFAs on June 25, 2004. Approximately 10 GFAs were disputed, and hearings were held June 30, 2004 and July 1, 2004. The other GFAs are not disputed. The primary disputed issues related to responsibility for Midwest ISO TEMT charges that might be billed for loads served under the GFAs. Proposed findings of fact and legal memoranda were filed ~~with~~regarding the disputed GFAs on July 5, 2004. The Administrative Law Judges (ALJ) submitted their recommendations to the FERC byon July 28, 2004, recommending that NSP-Minnesota and NSP-Wisconsin generally be found to be the entity financially responsible for TEMT costs for loads served under their GFAs. The ALJ order is subject to further FERC consideration, and Xcel Energy plans to contest the ALJ recommendation. FERC is expected to issue a final decision later in 2004. Xcel Energy also submitted a request for rehearing of the May ~~7, 2004.~~ 26, 2004 order, alleging the expedited hearing process violates both the U.S. Constitution and the federal Administrative Procedure Act.

Implementation of a wholesale regional market using the locational marginal cost pricing and financial transmission rights is expected to provide a benefit to NSP-Minnesota and NSP-Wisconsin through a reduction in overall power costs. However, Xcel Energy opposes certain aspects of the ~~tariff~~TEMT as proposed, and believes the Midwest ISO should implement the new market mechanisms only after it demonstrates that it will protect reliability. Xcel Energy cannot at this time estimate the total financial impact of the new market structure.

Private Fuel Storage– NSP-Minnesota is part of a consortium of private parties working to establish a private facility for interim storage of spent nuclear fuel. In 1997, Private Fuel Storage, LLC filed a license application with the Nuclear Regulatory Commission (NRC) for a temporary storage site for spent nuclear fuel on the Skull Valley Indian Reservation in Utah. Most issues raised by opponents were favorably resolved or dismissed, however, the likelihood of certain aircraft crashes into the proposed facility was deemed sufficiently credible to be addressed. On May 11, 2004, the NRC issued a safety evaluation report documenting its evaluation of aircraft crash consequences on casks at the proposed private storage facility. The report concluded that an accidental aircraft or ordnance impact at the proposed facility does not pose a credible hazard to public health and safety. The next step is the Atomic Safety and Licensing Board (ASLB) hearings scheduled to begin on August 9, 2004. If successful during these hearings, the ASLB could forward their recommendation in late 2004, and a license could be issued in early 2005.

Minnesota Service Quality Investigation– On Nov. 14, 2003, NSP-Minnesota submitted a proposed service quality plan and an update regarding certain service quality settlement agreement provisions already implemented by NSP-Minnesota. Among other provisions, the proposed service quality plan contains underperformance payments for the failure to meet certain reliability anand customer service metrics. On March 10, 2004, the Minnesota Public Utilities Commission (MPUC) issued an order approving the settlement, but modifying it to include an annual independent audit of NSP-Minnesota’s service outage records and requiring additional under-performance payments for any future finding of inaccurate data by an independent auditor. Both state agencies and NSP-Minnesota have the option under the settlement to void the agreement in the event of a significant modification by the MPUC. On ~~March 29,~~May 13, 2004, ~~NSP-Minnesota submitted a~~the MPUC declined to act on both NSP-Minnesota’s Petition for Clarification of the MPUC’s March 10th ~~order. Another party also~~order and that of another party’s Petition for Reconsideration. On June 2, 2004, NSP-Minnesota submitted a ~~Petition~~compliance tariff implementing the terms of the MPUC order, including modifications to the settlement. NSP-Minnesota indicated that, if approved by the MPUC, it would accept the terms of the order; if rejected or modified by the MPUC, it would reject the terms of the order. The MPUC is expected to consider this compliance filing later in 2004.

NSP-Minnesota Combustion Turbine Proposal —In November 2003, NSP-Minnesota proposed investing approximately $164 million in generating capacity in Minnesota and South Dakota to ensure adequate electric capacity for ~~Reconsideration~~its Upper Midwest customers. NSP-Minnesota has received all regulatory approvals for a $100-million project to add two combustion turbines at its Blue Lake peaking plant in Shakopee, Minn., and for a $64-million project to add one turbine at its Angus Anson peaking plant in Sioux Falls, S.D.

Each of the three new turbines would be fired by natural gas and would have a summer capacity of approximately 160 megawatts. Currently, the Blue Lake plant has four units fired by oil and a net dependable capacity of 174 megawatts; the Angus Anson plant has two units that can be fired by either natural gas or oil and a net dependable capacity of 226 megawatts.

As of June 30, 2004, all required state regulatory approvals for these projects have been received, including a certificate of need for the Blue Lake project from the MPUC, a site permit from the Minnesota Environmental Quality Board, air quality permits from the Minnesota Pollution Control Agency, the amended facility permit for the Anson project from the South Dakota Public Utilities Commission and air quality permits from the South Dakota Department of Environment and Natural Resources. Construction on the ~~same date.~~projects has begun. The ~~MPUC has scheduled a hearing for May 13, 2004~~projects also require approval by Midwest ISO with regard to ~~consider these petitions.~~interconnection and transmission service

1113

requests, which is pending.

NRG Tax Complaint —In November 2003, an NSP-Minnesota customer filed a complaint with the MPUC alleging that ratepayers are entitled to a share of the tax benefits attributable to NRG. The customer subsequently supplemented this complaint with sufficient signatures from customers to warrant a formal complaint process by the MPUC. NSP-Minnesota has responded to the complaint, arguing that the requested treatment is not allowed by law and is inconsistent with the MPUC’s directives to ensure full separation of NSP-Minnesota and NRG. The Minnesota Department of Commerce has filed comments recommending denial of the complaint. The Office of the Attorney General indicated that the MPUC should credit Minnesota ratepayers with that portion of the NSP-Minnesota rate that was allocated for tax payments, but never paid as such, applying the credit in a future rate proceeding. NSP-Minnesota is preparing a response against this recommendation. The MPUC is expected to consider this matter later this year.

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

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

As part of its resource plan, PSCo is seeking the waiver of certain CPUC rules, towhich would allow it to build a new 750 megawatt coal-fired unit at its existing Comanche power plant site located in Pueblo, Colorado. PSCo plans to own 500 megawatts of this new facility. Two of PSCo’s wholesale customers have options to participate in the ownership of the remaining 250 megawatts, and PSCo is in discussions with them regarding the plant’s development. ~~In addition to~~

On April 30, 2004, PSCo also filed an application requesting a certificate of public convenience and necessity for the new coal ~~unit,~~unit. PSCo is requesting in a separate application for CPUC authorization to construct and own the transmission facilities necessary to tie the new facility into PSCo’s high voltage transmission network. PSCo is also ~~filing~~filed a separate application for a specific regulatory plan to address the impacts of purchased capacity contracts on its capital structure and to ~~expedite~~accelerate the recovery of the costs of financing the new power plant and related ~~transmission.~~transmission prior to commercial operations. The CPUC has consolidated these three applications and has scheduled hearings in November 2004. A decision is expected in late 2004 or early 2005. The procedural schedule is as follows:


•	PSCo Supplemental Direct Testimony	August 13
•	Intervenor Answer Testimony	September 13
•	PSCo Rebuttal and Intervenor Answer Testimony	October 18
•	Hearings	November 1 – 19
•	Statements of Position	December 3
•	Commission Decision	December 15-January 15

The CPUC is expected to decide in a separate docket PSCo’s request for approval of a 500 megawatt renewable energy solicitation with a hearing scheduled for August 2004.

PSCo Capacity Cost Adjustment- In October 2003, PSCo filed an application to recover incremental capacity costs through a purchased capacity cost adjustment (PCCA) rider. The PCCA ~~is designed to~~will recover purchased capacity payments to power suppliers that are not included in the determination of PSCo’s ~~current~~ base electric rates determined in its 2002 general rate case or other recovery mechanisms. ~~Based on~~In May 2004, the CPUC granted the PSCo PCCA application, in part with new rates effective June 1, 2004. Primary provisions of the CPUC ruling include a capped PCCA recovery for the period June 1, 2004 through Dec. 31, 2006 at PSCo’s current ~~request, the~~predicted capacity ~~rider is expected to recover approximately $27~~payments for a group of specific contracts, which will provide recovery of $20.4 million in 2004, ~~$44~~$33.5 million in 2005 and ~~$38~~$19.8 million in 2006. In addition, the CPUC excluded seven of the existing contracts from incremental recovery under the PCCA calculation. However, PSCo ~~has proposed~~expects that the capacity costs from these contracts will be eligible for recovery through base rates when PSCo files its next general rate case. The energy costs from these contracts are eligible for recovery through the PSCo electric commodity adjustment clause.

On July 16, 2004, PSCo filed an Application for Rehearing, Reargument and Reconsideration (ARRR) asking the CPUC to ~~refund~~grant rehearing on its decision specifying that the PCCA recovery be limited to budget estimates of purchased capacity costs, instead asking for full recovery of actual purchased capacity payments. Second, the ARRR requests that the CPUC modify its ~~retail customers 100 percent~~decision to allow PSCo to reflect the relationship of ~~any~~the Air Quality Improvement Rider (AQIR) to the 2004 PCCA rider eliminating the actual amount of double recovery of purchased capacity expense that results from the interaction of PSCo’s AQIR and the PCCA. The existing CPUC decision assumes a double recovery, which is $750,000 greater than the actual amount.

PSCo Electric Department Earning Test Proceedings– As a part of PSCo’s annual electric earnings ~~in excess~~test, the CPUC has opened a docket to consider whether PSCo’s cost of debt has been adversely affected by the financial difficulties at NRG and, if so, whether any adjustments to PSCo’s cost of capital are appropriate. In its earnings test for 2002, PSCo did not earn above its allowed authorized ~~rate of~~ return on equity ~~currently 10.75 percent, through 2006. The~~and, accordingly, has not recorded any refund obligations. There was no earnings test for 2003.

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

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

As of Dec. 31, 2003, PSCo had accrued an aggregate estimated bill credit obligation of $6.4 million for the 2002 and 2003 calendar years. Based on the updated information and filings discussed above, during the second quarter of 2004, PSCo increased its estimated bill credit liability for these years to $13.4 million. The CPUC’s final approval of the achieved performance measures for 2002 and 2003 is pending. For calendar year 2004, PSCo has evaluated its year to date performance under the QSP and has recorded an additional liability of $5.4 million for the six months ended June 30, 2004. Under the electric QSP, the estimated maximum potential bill credit obligation for calendar 2004 performance is approximately $15.2 million, assuming none of the performance targets are met.

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

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

SPS Texas Fuel Cost Recovery –Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor. In May 2004, SPS filed its periodic request for fuel and purchased power cost recovery for electric generation and fuel management activities for the period from January 2002 through December 2003. SPS requested to recover approximately $580

million of Texas-jurisdictional fuel and purchased power costs for the two-year period. The proceeding has been set for hearing in December 2004, and a decision regarding SPS fuel and purchased power costs incurred through December 2003 is expected in the second quarter of 2005.

In November 2003, SPS submitted a fuel cost surcharge factor application in Texas to recover an additional $25 million of fuel cost under-recoveries accrued during June through September 2003. In February 2004, the parties in the proceeding submitted a unanimous settlement allowing SPS to collect net under-recoveries experienced through December 2003 of $22 million. The surcharge, which was approved by the ~~CPUC as a part~~Public Utility Commission of ~~a 1999 resource plan~~Texas (PUCT) in March 2004, went into effect May 2004 and ~~the resources~~will continue for 12 months.

In May 2004, SPS filed another fuel cost surcharge factor application in ~~base rates should factor into the PCCA calculation. Over the period 2004~~Texas to recover an additional $32 million of fuel cost recoveries accrued during January through ~~2006, the CPUC staff and OCC position would reduce the PCCA revenue requested by PSCo by approximately one third. Hearings were held in April~~March 2004. ~~Based on the current schedule, PSCo expects a final decision with new rates in effect in~~In June 2004, if the ~~CPUC approves~~parties in the ~~PCCA.~~proceeding submitted a unanimous settlement allowing SPS to collect the $32 million fuel cost under-recoveries surcharge factors for a 12-month period beginning November 2004. The unanimous settlement is pending review and approval by the PUCT.

6. Commitments and Contingent Liabilities

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

Environmental Contingencies–

Xcel Energy and its subsidiaries have been or are currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, the subsidiary involved is pursuing or intends to pursue insurance claims and believes it will recover some portion of these costs through such claims. Additionally, where applicable, the subsidiary involved is pursuing, or intends 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 would be required to recognize an expense for such unrecoverable amounts in its consolidated financial statements.

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

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

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

to $9 million. To date, PSCo has spent approximately $1.8 million on the project, including settlement costs negotiated with Fort Collins in 1998. The EPA has also conducted work over the past two years, incurring estimated costs of approximately $1 million to date, for which they will likely seek recovery from PSCo at a future date.

While PSCo has recorded a liability of $7.6 million at June 30, 2004, it lacks sufficient information at this time to determine its ultimate liability for clean up, if different, for this site. PSCo has deferred the costs recorded to date and believes that they will be recovered through future rates. Any costs that are not recoverable from customers will be expensed.

Federal Clean Water Act– The Federal Clean Water Act addresses the environmental impacts of cooling water intakes. In July 2004, the EPA published phase II of the rule that applies to existing cooling water intakes at steam-electric power plants. The rule will require Xcel Energy to perform additional environmental studies at 12 power plants in Minnesota, Wisconsin and Colorado to determine the impact the facilities may be having on aquatic organisms vulnerable to impingement or entrainment. If the studies determine the plants are not meeting the new performance standards established by the phase II rule, physical and/or operational changes may be required at these facilities. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved. Preliminary cost estimates range from less than $1 million at some facilities to more than $10 million at others depending on site-specific circumstances. Based on the limited information available, total cost to Xcel Energy is estimated at approximately $64 million. Actual costs may be significantly higher or lower depending on issues such as the resolution of outstanding third-party legal challenges to the rule.

Legal Contingencies

Bender, et al. vs. Xcel Energy– On July 2, 2004, five former NRG officers filed a lawsuit against Xcel Energy in the U.S. District Court for the District of Minnesota. The lawsuit alleges, among other things, that Xcel Energy violated the Employee Retirement Income Security Act of 1974 (ERISA) by refusing to make certain deferred compensation payments to the plaintiffs. The complaint also alleges interference with ERISA benefits, breach of contract related to the nonpayment of certain stock options and unjust enrichment. The complaint alleges damages of approximately $6 million. Xcel Energy believes the suit is without merit.

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

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

Xcel Energy Inc. Shareholder Derivative Action — Edith Gottlieb vs. Xcel Energy Inc. et al; Essmacher vs. Brunetti; McLain vs. Brunetti —In August 2002, a shareholder derivative action was filed in the U.S. District Court for the District of Minnesota (Gottlieb), purportedly on behalf of Xcel Energy, against the directors and certain present and former officers, citing allegedly false and misleading disclosures concerning various issues and asserting breach of fiduciary duty. This action has been consolidated for pre-trial purposes with other similar securities class actions and an amended complaint was filed. Two additional derivative actions were filed in the state trial court in Hennepin County, Minn. (Essmacher and McLain), against essentially the same defendants, focusing on allegedly wrongful energy trading activities and asserting breach of fiduciary duty for failure to establish adequate accounting controls, abuse of control and gross mismanagement. Considered collectively, the complaints seek compensatory damages, a return of

NSP-Minnesota Natural Gas Customer Billing Errors– In July 2004, NSP-Minnesota made a filing with the MPUC that identified a number of natural gas customers in Minnesota and North Dakota that were over billed because of an incorrect setting on a wireless meter reading device installed on customer meters beginning in late 1998. The incorrect setting occurred when the wireless devices were attached to older meters, allowing them to be read remotely.

Based on analyses of past meter purchases and associated serial numbers, NSP-Minnesota believes the error may have affected approximately 3,200 older residential natural gas meters, but is still determining the number of potential additional residential and commercial natural gas customers that may also be affected. Of the field verifications completed to date, NSP-Minnesota has determined that approximately 12 percent of the devices were incorrectly set. While the problem resulted in some customers being charged for half of their natural gas usage, the verifications made to date indicate that the majority of those who received incorrect bills were charged for twice their actual natural gas usage. NSP-Minnesota is continuing to test meters and will make refunds, if overcharging is found. The number of customers affected and the total amount of refunds will not be known until NSP-Minnesota completes such testing, which is expected to be completed in August 2004. As of June 30, 2004, NSP-Minnesota had accrued $2.4 million based on information currently available. At this time, Xcel Energy is not aware of what action its state regulators may take relating to this matter.

Other Contingencies–- The circumstances set forth in Notes 15, 17 and 18 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2003 and Note 4 of this Quarterly Report on Form 10-Q, appropriately represent, in all material respects, the current status of other commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident, and are incorporated herein by reference. ~~The following are unresolved contingencies that are material to Xcel Energy’s financial position:~~

• ~~Tax Matters — See Note 4 to the accompanying consolidated financial statements for discussion of exposures regarding the tax deductibility of corporate-owned life insurance loan interest; and~~
• ~~Guarantees — See Note 7 to the accompanying consolidated financial statements for discussion of exposures under various guarantees.~~

7. Short-Term Borrowings and Other Financing Instruments

Short-Term Borrowings

At ~~March 31,~~June 30, 2004, Xcel Energy and its subsidiaries had approximately ~~$91~~$124 million of short-term debt outstanding at a weighted average interest rate of ~~1.93~~2.94 percent.

Guarantees

Xcel Energy provides various guarantees and bond indemnities supporting certain of its subsidiaries. The guarantees issued by Xcel Energy guarantee payment or performance by its subsidiaries under specified agreements or transactions. As a result, Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees issued by Xcel Energy limit the exposure of Xcel Energy to a maximum amount stated in the guarantees. On ~~March 31,~~June 30, 2004, Xcel Energy had issued guarantees of up to ~~$89~~$68 million with no$1 million of exposure under these guarantees. In addition, Xcel Energy provides indemnity protection for bonds issued by itself and its subsidiaries. The total amount of bonds with this indemnity outstanding as of ~~March 31,~~June 30, 2004, was approximately ~~$29~~$108 million. The total exposure of this indemnification cannot be determined at this time. Xcel Energy believes the exposure to be significantly less than the total amount of bonds outstanding.

8. Derivative Valuation and Financial Impacts

Xcel Energy records all derivative instruments on the balance sheet at fair value unless exempted as a normal purchase or sale. Changes in non-exempt derivative instrument’s fair value are recognized currently in earnings unless the derivative has been designated in a qualifying hedging relationship. The application of hedge accounting allows a derivative instrument’s gains and losses to offset related results of the hedged item in the statement of operations, to the extent effective. ~~Statement of Financial Accounting Standard (SFAS)~~SFAS No. 133 ~~as amended,~~– “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), as amended, requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

The impact of the components of hedges on Xcel Energy’s Other Comprehensive Income, included in the Consolidated Statements of Stockholders’ Equity, are detailed in the following tables:


							Three months ended
							June 30,
(Millions of Dollars)	2004			2003			2004			2003
Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	8.1		$	22.1
After-tax net unrealized losses related to derivatives accounted for as hedges		(2.9	)		(35.8	)
Accumulated other comprehensive income (loss) related to cash flow hedges at March 31							$	2.6		$	(32.6	)
After-tax net unrealized gains related to derivatives accounted for as hedges								16.7			12.1
After-tax net realized gains on derivative transactions reclassified into earnings		(2.6	)		(18.9	)		(1.2	)		(18.0	)

Accumulated other comprehensive income (loss) related to cash flow hedges at March 31	$	2.6		$	(32.6	)
Accumulated other comprehensive income (loss) related to cash flow hedges at June 30							$	18.1		$	(38.5	)

Xcel Energy records the fair value of its derivative instruments in its Consolidated Balance Sheet as a separate line item identified as Derivative Instruments Valuation for assets and liabilities, as well as current and noncurrent.

markets, the value in Other Comprehensive Income will likely change prior to its recognition in earnings.

Xcel Energy and its subsidiaries enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. Xcel Energy expects to recognize in earnings during the next 12 months net ~~losses~~gains from Other Comprehensive Income related to interest rate cash flow hedge contracts of approximately $0.1 million.

Gains or losses on hedging transactions for the sales of electric energy are recorded as a component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs, hedging transactions for gas purchased for resale are recorded as a component of gas costs and interest rate hedging transactions are recorded as a component of interest expense. Certain Xcel Energy utility subsidiaries are allowed to recover in electric or gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. There was no hedge ineffectiveness in the ~~first~~second quarter of 2004.

Fair Value Hedges

Xcel Energy enters into interest rate swap instruments that effectively hedge the fair value of fixed rate debt. Changes in the fair value of hedges designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of related hedged assets, liabilities or firm commitments.

The fair value of all interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.

Derivatives Not Qualifying for Hedge Accounting

Xcel Energy and its subsidiaries have trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market basis in the Consolidated Statements of Operations. The results of these transactions are recorded ~~within~~as a component of Operating Revenues on the Consolidated Statements of Operations.

Xcel Energy and its subsidiaries also enter into certain commodity-based transactions, not included in trading operations, which do not qualify for hedge accounting treatment. These derivative instruments are accounted for on a mark-to-market basis in the Consolidated Statement of Operations. The results of these transactions are recorded as a component of Operating Expenses on the Consolidated Statement of Operations.

Normal Purchases or Normal Sales Contracts

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

Xcel Energy evaluates all of its contracts within the regulated and nonregulated operations 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.


	Six months ended June 30,
	2004			2003				2004			2003
(Thousands of dollars)							Postretirement Health
Xcel Energy Inc.	Pension Benefits							Care Benefits
Service cost	$	29,474		$	33,734			$	3,050		$	2,945
Interest cost		82,674			85,376				26,302			26,213
Expected return on plan assets		(151,532	)		(161,028	)			(11,626	)		(11,092	)
Amortization of transition (asset) obligation		(4	)		(998	)			7,290			7,713
Amortization of prior service cost (credit)		15,006			14,124				(1,090	)		(766	)
Amortization of net (gain) loss		(7,718	)		(22,420	)			10,826			7,705

Net periodic benefit cost (credit)		(32,100	)		(51,212	)			34,752			32,718
Settlements and curtailments		703			1,309				—			(2,128	)
Costs not recognized due to the effects of regulation		18,745			25,545				—			—
Additional cost recognized due to the effects of regulation		—			—				1,945			1,938

Net benefit cost (credit) recognized for financial reporting	$	(12,652	)	$	(24,358	)		$	36,697		$	32,528

Employer Contributions

In its Annual Report on Form 10-K for the year ending Dec. 31, 2003, Xcel Energy disclosed that it expected to contribute $10 million to one of its pension plans in 2004. This contribution has not yet been made, but Xcel Energy anticipates that it will be made before year end 2004. Xcel Energy anticipates contributing $55 million during 2004 to fund its retiree medical and life insurance plans.

12. Segment Information

Xcel Energy has the following reportable segments: Regulated Electric Utility, Regulated Natural Gas Utility and All Other. Trading operations performed by regulated operating companies are not a reportable segment. Electric trading results are included in the Regulated Electric Utility segment.


	Regulated		Regulated										Regulated		Regulated
	Electric		Natural Gas		All			Reconciling			Consolidated		Electric		Natural Gas			All			Reconciling			Consolidated
(Thousands of Dollars)	Utility		Utility		Other			Eliminations			Total		Utility		Utility			Other			Eliminations			Total
Three months ended March 31, 2004
Three months ended June 30, 2004
Operating revenues from external customers	$	1,473,600	$	762,808	$	54,177		$	—		$	2,290,585	$	1,477,176	$	273,365		$	56,810		$	—		$	1,807,351
Intersegment revenues		283		3,456		7,710			(11,449	)		—		261		2,205			10,566			(13,032	)		—

Total revenues	$	1,473,883	$	766,264	$	61,887		$	(11,449	)	$	2,290,585	$	1,477,437	$	275,570		$	67,376		$	(13,032	)	$	1,807,351

Income (loss) from continuing operations	$	105,325	$	48,234	$	722		$	(9,983	)	$	144,298	$	83,544	$	(2,185	)	$	4,969		$	(5,151	)	$	81,177

Three months ended March 31, 2003
Three months ended June 30, 2003
Operating revenues from external customers	$	1,364,344	$	654,272	$	56,941		$	—		$	2,075,557	$	1,379,975	$	266,741		$	65,743		$	—		$	1,712,459
Intersegment revenues		296		1,386		9,264			(10,946	)		—		265		2,162			13,983			(16,410	)		—

Total revenues	$	1,364,640	$	655,658	$	66,205		$	(10,946	)	$	2,075,557	$	1,380,240	$	268,903		$	79,726		$	(16,410	)	$	1,712,459

Income (loss) from continuing operations	$	86,007	$	55,255	$	(4,081	)	$	(11,215	)	$	125,966	$	69,355	$	3,809		$	(4,744	)	$	(13,761	)	$	54,659

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,” “projected,” “possible,” “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:

• Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;

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

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

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

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

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

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

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

• Increased competition in the utility industry or additional competition in the markets served by Xcel Energy and its subsidiaries;

• 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; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

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

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

• Social attitudes regarding the utility and power industries;

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

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

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

• Risks associated with implementations of new technologies;

RESULTS OF OPERATIONS

Summary of Financial Results

The following table summarizes the earnings contributions of Xcel Energy’s business segments on the basis of GAAP. Continuing operations consist of the following:

• regulated utility subsidiaries, operating in the electric and natural gas segments; and

• several nonregulated subsidiaries and the holding company, where corporate financing activity occurs.

Discontinued operations consist of the following:

• the regulated natural gas businesses Viking and BMG, which were sold in 2003;

• the regulated utility business of CLF&P for which a sale agreement was entered into in early 2004;

• NRG, which emerged from bankruptcy in late 2003, at which time Xcel Energy divested its ownership interest in NRG; and

• the nonregulated subsidiaries Xcel Energy International and e prime, which were classified as held for sale in late 2003 based on the decision to divest them.

Prior-year financial statements have been restated to conform to the current year presentation and classification of certain operations as discontinued. See Note 2 to the consolidated financial statements for a further discussion of discontinued operations.

Three months ended
March 31,
Contribution to Earnings (Millions of dollars)
2004
2003
GAAP income (loss) by segment

Regulated electric utility segment income — continuing operations $ 105.3 $ 86.0
Regulated natural gas utility segment income — continuing operations 48.2 55.3
Other utility results (a) 4.3 3.5

Total utility segment income — continuing operations 157.8 144.8
Other nonregulated results and holding company costs (a) (13.5 ) (18.8 )

Total income — continuing operations 144.3 126.0
Regulated utility income — discontinued operations 0.8 22.8
NRG loss — discontinued operations — (11.6 )
Other nonregulated income — discontinued operations 4.8 2.8

Total income — discontinued operations 5.6 14.0

Total GAAP income $ 149.9 $ 140.0

Three months ended
March 31,
2004
2003
GAAP earnings per share contribution by segment

Regulated electric utility segment — continuing operations $ 0.25 $ 0.21
Regulated natural gas utility segment — continuing operations 0.11 0.13
Other utility results (a) 0.01 0.01

Total utility segment earnings per share — continuing operations 0.37 0.35
Other nonregulated results and holding company costs (a) (0.02 ) (0.04 )

Total earnings per share — continuing operations 0.35 0.31
Regulated utility earnings — discontinued operations — 0.05
NRG loss — discontinued operations — (0.03 )
Other nonregulated earnings — discontinued operations 0.01 0.01

Total earnings per share — discontinued operations 0.01 0.03

Total GAAP earnings per share — diluted $ 0.36 $ 0.34


	Three months ended
	June 30,
Contribution to Earnings (Millions of dollars)	2004			2003
GAAP income (loss) by segment
Regulated electric utility segment income — continuing operations	$	83.5		$	69.4
Regulated natural gas utility segment income (loss) — continuing operations		(2.1	)		3.8
Other utility results (a)		7.4			4.0

Total utility segment income — continuing operations		88.8			77.2
Other nonregulated results and holding company costs (a)		(7.6	)		(22.6	)

Total income — continuing operations		81.2			54.6
Regulated utility income — discontinued operations		0.6			0.5
NRG loss — discontinued operations		—			(350.5	)
Other nonregulated income — discontinued operations		4.5			12.8

Total income (loss) — discontinued operations		5.1			(337.2	)

Total GAAP income (loss)	$	86.3		$	(282.6	)

1824


	Six months ended
	June 30,
Contribution to Earnings (Millions of dollars)	2004			2003
GAAP income (loss) by segment
Regulated electric utility segment income — continuing operations	$	188.9		$	155.4
Regulated natural gas utility segment income — continuing operations		46.0			59.1
Other utility results (a)		11.7			7.6

Total utility segment income — continuing operations		246.6			222.1
Other nonregulated results and holding company costs (a)		(21.1	)		(41.5	)

Total income — continuing operations		225.5			180.6
Regulated utility income — discontinued operations		1.4			23.3
NRG loss — discontinued operations		—			(362.2	)
Other nonregulated income — discontinued operations		9.3			15.7

Total income (loss) — discontinued operations		10.7			(323.2	)

Total GAAP income (loss)	$	236.2		$	(142.6	)


	Three months ended
	June 30,
	2004			2003
GAAP earnings per share contribution by segment
Regulated electric utility segment — continuing operations	$	0.20		$	0.17
Regulated natural gas utility segment — continuing operations		(0.01	)		0.01
Other utility results (a)		0.02			0.01

Total utility segment earnings per share — continuing operations		0.21			0.19
Other nonregulated results and holding company costs (a)		(0.01	)		(0.06	)

Total earnings per share — continuing operations		0.20			0.13
Regulated utility earnings — discontinued operations		—			—
NRG loss — discontinued operations		—			(0.85	)
Other nonregulated earnings — discontinued operations		0.01			0.01

Total earnings (loss) per share — discontinued operations		0.01			(0.84	)

Total GAAP earnings (loss) per share — diluted	$	0.21		$	(0.71	)


	Six months ended
	June 30,
	2004			2003
GAAP earnings per share contribution by segment
Regulated electric utility segment — continuing operations	$	0.44		$	0.37
Regulated natural gas utility segment — continuing operations		0.11			0.14
Other utility results (a)		0.03			0.02

Total utility segment earnings per share — continuing operations		0.58			0.53
Other nonregulated results and holding company costs (a)		(0.04	)		(0.09	)

Total earnings per share — continuing operations		0.54			0.44
Regulated utility earnings — discontinued operations		—			0.06
NRG loss — discontinued operations		—			(0.84	)
Other nonregulated earnings — discontinued operations		0.03			0.01

Total earnings (loss) per share — discontinued operations		0.03			(0.77	)

Total GAAP earnings (loss) per share — diluted	$	0.57		$	(0.33	)

(a) Not a reportable segment. Included in All Other segment results in Note 12 to the consolidated financial statements. Other utility results included in the earnings contribution table above includes certain subsidiaries of the utility operating companies that conduct non-utility activities. The largest of these other utility businesses is PSRI, a subsidiary of PSCo that owns and manages life insurance

For the ~~first~~second quarter of 2004, net income from utility operations increased largely due to ~~strong~~lower depreciation expense, higher short-term wholesale margins ~~sales~~and customer growth, ~~and lower depreciation expense in 2004,~~ partially offset by ~~higher purchased capacity costs~~quality of service penalties in Colorado and higher utility operating and maintenance expenses. ~~See below for additional discussion of specific margin and cost items affecting utility operating results.~~

The following summarizes the estimated impact of weather on regulated utility earnings per share, based on estimated temperature variations from historical averages (excluding the impact on energy trading operations):

The following table summarizes the ~~earnings-per-share~~earnings per share contributions of Xcel Energy’s nonregulated businesses and holding company ~~results:~~results.

Discontinued ~~- -~~ Utility ~~Segments~~Operations– During January��2004, Xcel Energy reached an agreement to sell its regulated electric and natural gas subsidiary, CLF&P. As a result of this agreement, Xcel Energy ~~considers~~is reporting CLF&P ~~held for sale and reports its~~ results as a component of discontinued operations for all periods presented. The sale is pending regulatory approval and is expected to be completed ~~during 2004. CLF&P contributed approximately $789,000 to net income, which is less than 1 cent of earnings per share, for the three months ended March 31,~~in 2004.

During 2003, Xcel Energy completed the sale of two subsidiaries in its regulated natural gas utility segment, ~~Black Mountain Gas Co.~~BMG and Viking, ~~Gas Transmission Co,~~ including ~~its~~Viking’s interest in Guardian Pipeline, LLC. As a result, a gain of 5 cents per share was recorded in the first quarter of 2003 related to the sale of ~~Viking Gas.~~Viking. The BMG sale was completed in the third quarter of 2003.

Discontinued -Nonregulated Operations - NRG-– Xcel Energy’s share of NRG’s ~~asset impairments~~results for 2003 and ~~related charges in 2003 include approximately $40 million in first-quarter charges related~~prior periods are reported as a component of discontinued operations due to NRG’s ~~NEO landfill gas projects~~emergence from bankruptcy in December 2003 and ~~equity investments.~~Xcel Energy’s corresponding relinquishment of its ownership interest in NRG. See additional discussion of NRG’s bankruptcy and divestiture in Notes 2 and 3 to the consolidated financial statements.

Discontinued Nonregulated Operations – ~~All~~ Other Subsidiaries –During 2003, the board of directors of Xcel Energy approved management’s plan to exit businesses conducted by Xcel Energy International and e prime. Xcel Energy International primarily includes power generation projects in Argentina. e prime provided energy-related products and services, which included natural gas commodity trading and marketing and energy consulting.

~~Xcel Energy sold~~ The exit of all ~~of the contractual assets of~~business conducted by e prime ~~during the first quarter of~~was completed in 2004.

During the first quarter of 2004, Xcel Energy completed the sale of one of its Argentina subsidiaries, Hidroelectrica del Sur S.A. (HDS). The sale price of HDS was immaterial and approximated the book value of Xcel Energy’s investment in HDS.

On June 3, 2004, Xcel Energy sold another of its Argentina subsidiaries, Corporacion Independiente de Energia S.A. (CIESA), which has as its primary asset a 620-megawatt gas/oil-fired facility in Argentina. The sale also included the stock of IPC Operations Limited, an energy services company with operations in Argentina. The total purchase price was approximately $26 million. Approximately $15 million of the purchase price has been placed in escrow, which is expected to remain in place until the first quarter of 2005, to support customary indemnity obligations under the purchase agreement. In addition to the purchase price, Xcel Argentina also received approximately $21 million at closing as a redemption of its capital from CIESA. The sale resulted in an after-tax gain of $6.1 million, or 1 cent per share, in the second quarter of 2004. The gain includes the realization of $6.9 million of tax benefits related to the now-realizable tax loss from disposition of Xcel Argentina assets.

Xcel Energy International is in the process of marketing its remaining assets and operations to prospective buyers and expects to exit the businesses during 2004.

During the first quarter of 2004, Xcel Energy recorded earnings from discontinued operations of 1 cent per share related to ongoing activity at the remaining businesses of Xcel Energy International and a tax benefit true up related to NRG.

Income Statement Analysis — ~~First~~Second Quarter 2004 vs. ~~First~~Second Quarter 2003

Electric Utility and Commodity Trading Margins

Electric fuel and purchased power expenses 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 in several states, most fluctuations in energy costs do not materially affect electric utility margin.

Xcel Energy has two distinct forms of wholesale sales: short-term wholesale and electric commodity trading. Short-term wholesale refers to electric sales for resale, which are associated with energy produced from Xcel Energy’s generation assets or energy 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. Short-term wholesale and electric commodity trading activities are considered part of the electric utility segment.

Xcel Energy’s electric commodity trading operations are conducted by NSP-Minnesota and PSCo. Margins from electric trading activity are partially redistributed to other operating utilities of Xcel Energy, pursuant to a joint operating agreement approved by the FERC. PSCo’s short-term wholesale margins and electric trading margins reflect the estimated impacts of regulatory sharing, if applicable, of certain margins with Colorado retail customers. Trading revenues are reported net of related costs (i.e., on a margin basis) in the Consolidated Statements of Operations. The NRG and e prime trading activity for 2003 is presented in discontinued operations and is not reflected in the following table.

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


	Base			Short-			Electric						Base			Short-			Electric
	Electric			Term			Commodity			Consolidated			Electric			Term			Commodity			Consolidated
(Millions of Dollars)	Utility			Wholesale			Trading			Total			Utility			Wholesale			Trading			Total
Three months ended March 31, 2004
Three months ended June 30, 2004
Electric utility revenue	$	1,411		$	58		$	—		$	1,469		$	1,417		$	59		$	—		$	1,476
Electric fuel and purchased power		(658	)		(21	)		—			(679	)		(691	)		(32	)		—			(723	)
Electric trading revenue-gross		—			—			86			86			—			—			150			150
Electric trading costs		—			—			(82	)		(82	)		—			—			(149	)		(149	)

Gross margin before operating expenses	$	753		$	37		$	4		$	794		$	726		$	27		$	1		$	754

Margin as a percentage of revenue		53.4	%		63.8	%		4.7	%		51.1	%		51.2	%		45.8	%		0.7	%		46.4	%
Three months ended March 31, 2003
Three months ended June 30, 2003
Electric utility revenue	$	1,303		$	62		$	—		$	1,365		$	1,335		$	39		$	—		$	1,374
Electric fuel and purchased power		(551	)		(41	)		—			(592	)		(608	)		(31	)		—			(639	)
Electric trading revenue - gross		—			—			58			58			—			—			75			75
Electric trading costs		—			—			(59	)		(59	)		—			—			(69	)		(69	)

Gross margin before operating expenses	$	752		$	21		$	(1	)	$	772		$	727		$	8		$	6		$	741

Margin as a percentage of revenue		57.7	%		33.9	%		(1.7	)%		54.3	%		54.5	%		20.5	%		8.0	%		51.1	%

The following summarizes the components of the changes in base electric utility revenue and base electric utility margin for the three months ended ~~March 31:~~June 30:

Base electric utility revenues and margins increased largely due to weather-normalized retail sales growth of approximately 1.6 percent and higher capacity sales in Texas. Also increasing revenues was higher fuel and purchased power costs, which are largely passed through to customers. Partially offsetting the higher revenues and margins were lower retail sales volumes related to warmer than normal winter temperatures, mainly in Colorado. In addition, base electric utility margin was adversely affected by higher purchased capacity costs, primarily at PSCo. As discussed previously, a rate proceeding is currently pending before the CPUC to address the recovery of incremental purchased power capacity costs from retail customers in Colorado.

Short-term wholesale and electric commodity trading ~~sales~~ margins increased approximately ~~$21~~$14 million ~~for~~during the ~~first~~second quarter of ~~2004. First~~2004 compared with the second quarter of 2003. Second quarter 2004 short-term wholesale results reflect ~~the impact~~a number of ~~high~~market factors, including higher market prices and ~~a pre-existing contract, which expired in the first quarter of 2004. The 2004 trading and short-term wholesale margins are expected to be slightly less than 2003 margins.~~additional resources available for sale.

The following table details the changes in natural gas utility revenue and margin. The cost of natural gas tends to vary with changing sales requirements and the 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.

The following summarizes the components of the changes in natural gas revenue and margin for the three months ended ~~March 31:~~June 30:

~~Natural gas revenue increased mainly due to higher natural gas costs in 2004, which are passed through to customers.~~

Utility Other Operation and Maintenance Expenses for the second quarter of 2004 increased by approximately $14 million, or 3.8 percent, compared with the same period in 2003. The increase is primarily due to higher reliability costs of $6 million, lower pension credits of $5 million, higher information technology expense of $2 million and costs associated with the implementation of a new customer billing system of $2 million. The higher costs are partially offset by lower restricted stock expense related to the 2003 grant of $9 million. In second quarter 2004, no restricted stock expense was recorded.

Depreciation and amortization expense decreased by approximately $26 million, or 12.8 percent, for the second quarter of 2004, when compared with the second quarter of 2003. The following contributed to that decrease:

• During the second quarter of 2003, $10 million of depreciation expense was recorded for renewable development fund costs, which are largely recovered through NSP-Minnesota’s fuel clause mechanism,
• The Minnesota legislature authorized during 2003 additional spent nuclear fuel storage at the Prairie Island nuclear plant. In December 2003, the MPUC extended the authorized useful lives of the two generating units at the Prairie Island nuclear plant retroactive to Jan. 1, 2003. The 2003 annual reduction was recorded in the fourth quarter of 2003. Annual depreciation expense for 2004 is expected to be approximately $18 million lower than 2003, due to a change in the decommissioning accruals resulting from a related MPUC order and
• Effective July 1, 2003, the CPUC lengthened the depreciable lives of certain electric utility plant at PSCo as a part of the general Colorado rate case, which will reduce annual depreciation expense by $20 million.

Interest charges and financing costs decreased $14 million, or 11.6 percent, for the second quarter of 2004, compared with the same period in 2003. The decrease reflects savings from refinancing higher coupon debt during 2003. Interest expense was reduced by $5.1 million and $3.7 million in the second quarter of 2004 and 2003, respectively, for interest capitalized.

Income taxes increased by $14 million during the second quarter of 2004 compared with the same period in 2003. The increase was primarily due to increased pretax income in 2004 and a lower effective tax rate in 2003. The effective tax rate for continuing operations was 14.0 percent for the second quarter of 2004, compared with (2.2) percent for the same period in 2003. The second quarter 2004 effective rate is higher than in 2003 due to adjustments recorded in 2003 relating to state tax accruals and favorable income tax audit settlements. The effective tax rate for the second quarter of 2004 is lower than the forecasted 2004 annual rate due mainly to a larger ratio of tax credits to lower pretax income levels in the second quarter of 2003.

Income Statement Analysis — First Six Months of 2004 vs. First Six Months of 2003

Electric Utility and Commodity Trading Margins

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


	Base			Short-			Electric
	Electric			Term			Commodity			Consolidated
(Millions of Dollars)	Utility			Wholesale			Trading			Total
Six months ended June 30, 2004
Electric utility revenue	$	2,829		$	117		$	—		$	2,946
Electric fuel and purchased power		(1,349	)		(53	)		—			(1,402	)
Electric trading revenue-gross		—			—			236			236
Electric trading costs		—			—			(231	)		(231	)

Gross margin before operating expenses	$	1,480		$	64		$	5		$	1,549

Margin as a percentage of revenue		52.3	%		54.7	%		2.1	%		48.7	%
Six months ended June 30, 2003
Electric utility revenue	$	2,639		$	101		$	—		$	2,740
Electric fuel and purchased power		(1,159	)		(72	)		—			(1,231	)
Electric trading revenue-gross		—			—			133			133
Electric trading costs		—			—			(128	)		(128	)

Gross margin before operating expenses	$	1,480		$	29		$	5		$	1,514

Margin as a percentage of revenue		56.1	%		28.7	%		3.8	%		52.7	%

The following summarizes the components of the changes in base electric utility revenue and base electric utility margin for the six

months ended June 30:

Base Electric Utility Revenue


(Millions of dollars)	2004 vs. 2003
Fuel and purchased power cost recovery	$	142
Sales growth (excluding weather impact)		44
Firm wholesale		13
Quality of service obligations		(9	)
Renewable development fund (offset by decrease in depreciation expense)		(8	)
Estimated impact of weather		(5	)
Capacity sales		5
Other		8

Total base electric utility revenue increase	$	190

Base Electric Utility Margin


(Millions of dollars)	2004 vs. 2003
Sales growth (excluding weather impact)	$	32
Purchased capacity and other costs		(15	)
Quality of service obligations		(9	)
Renewable development fund (offset by decrease in depreciation expense)		(8	)
Capacity sales		5
Estimated impact of weather		(3	)
Other		(2	)

Total base electric utility margin increase	$	—

Short-term wholesale margins increased $35 million for the first six months of 2004 compared with the same period in 2003. The higher results reflect a number of market factors, including higher market prices, additional resources available for sale in the second quarter of 2004 and a pre-existing contract, which expired in the first quarter of 2004. A comparable contract was not in place in the first half of 2003.

Natural Gas Utility Margins


	Six Months Ended
	June 30,
(Millions of Dollars)	2004			2003
Natural gas utility revenue	$	1,036		$	921
Cost of natural gas sold and transported		(781	)		(645	)

Natural gas utility margin	$	255		$	276

The following summarizes the components of the changes in natural gas revenue and margin for the six months ended June 30:

Natural Gas Revenue


(Millions of dollars)	2004 vs. 2003
Sales growth (excluding weather impact)	$	(4	)
Estimated impact of weather on firm sales volume		(7	)
Purchased gas adjustment clause recovery		139
Base rate changes – Colorado		(14	)
Transportation and other		1

Total natural gas revenue increase	$	115

Natural Gas Margin


(Millions of dollars)	2004 vs. 2003
Sales growth (excluding weather impact)	$	(1	)
Estimated impact of weather on firm sales volume		(4	)
Base rate changes - Colorado		(14	)
Transportation and other		(2	)

Total natural gas margin decrease	$	(21	)

Nonregulated Operating Margins

The following table details the change in nonregulated revenue and margin, included in continuing operations.


	Six Months Ended
	June 30,
(Millions of Dollars)	2004			2003
Nonregulated and other revenue	$	111		$	123
Nonregulated cost of goods sold		(59	)		(74	)

Nonregulated margin	$	52		$	49

Non-Fuel Operating Expense and Other Costs

Utility Other Operation and Maintenance Expenses for the first ~~quarter~~six months of 2004 increased by approximately ~~$16~~$31 million, or ~~4.3~~4.0 percent, compared with the same period in 2003. The increase is primarily due to ~~higher employee related~~lower pension credit costs ~~including $ 9~~of $12 million, ~~of performance-based restricted stock unit accruals related to a 2003 grant;~~ higher medical and health ~~care~~insurance costs of ~~$7 million; and lower pension credits~~$6 million, higher reliability costs of $6 million, higher information technology expense of $6 million, costs associated with the implementation of a new customer billing system of $2 million and higher ~~401k match~~transmission system costs of $7$2 million. The ~~increase was~~higher costs are partially offset by lower ~~performance-based compensation~~plant outage costs of $5$9 million. In the first quarter of 2003, there were no restricted stock unit grant costs due to the implementation of the plan at the end of that quarter. The cost of the 2003 restricted stock unit grant has been fully accrued at March 31, 2004.

Depreciation and amortization expense decreased by approximately ~~$15~~$42 million, or ~~8.0~~10.5 percent, for the first ~~quarter~~six months of 2004, when compared with the ~~first quarter of~~same period in 2003. During 2003, the Minnesota legislature authorized additional spent nuclear fuel storage at the Prairie Island nuclear plant. In December 2003, the MPUC extended the authorized useful lives of the two generating units at the Prairie Island nuclear plant until 2013 and 2014, respectively, retroactiveThe following contributed to ~~Jan. 1, 2003. Annual depreciation expense for 2004 is expected to be approximately $18 million lower than 2003, due to a change in the decommissioning accruals resulting from a related order.~~that decrease:

In addition, effective July 1, 2003, the CPUC lengthened the depreciable lives of certain electric utility plant at PSCo as a part of the general Colorado rate case, which will reduce annual depreciation expense by $20 million. This action reduced 2003 depreciation expense by $10 million. Xcel Energy’s depreciation expense in 2004 will reflect the full year impact of this change.
• During the second quarter of 2003, $10 million of depreciation expense was recorded for renewable development fund costs, which are largely recovered through NSP-Minnesota’s fuel clause mechanism.
• The Minnesota legislature authorized during 2003 additional spent nuclear fuel storage at the Prairie Island nuclear plant. In December 2003, the MPUC extended the authorized useful lives of the two generating units at the Prairie Island nuclear plant, retroactive to Jan. 1, 2003. The 2003 annual reduction was recorded in the fourth quarter of 2003. Annual depreciation expense for 2004 is expected to be approximately $18 million lower than 2003, due to a change in the decommissioning accruals resulting from a related MPUC order.
• Effective July 1, 2003, the CPUC lengthened the depreciable lives of certain electric utility plant at PSCo as a part of the general Colorado rate case, which will reduce annual depreciation expense by $20 million.

Interest charges and ~~other income (expense) - net increased $8.3~~financing costs decreased $21 million, or 8.9 percent, for the ~~first quarter of~~six month period ended June 30, 2004, compared with the same period in 2003. The ~~increase~~decrease reflects savings from refinancing higher coupon debt during 2003. Interest expense was ~~primarily due to a decrease~~reduced by $11.3 million and $10.5 million in the ~~equity loss from unconsolidated affiliates of Utility Engineering from 2003~~year to date periods ended June 30, 2004 and ~~an increase in allowance~~June 30, 2003, respectively, for ~~equity funds used during construction.~~interest capitalized.

Income ~~tax expense~~taxes increased ~~by approximately $9 million~~ for the ~~first quarter of~~six months ended June 30, 2004 compared with the ~~first quarter of 2003.~~six months ended June 30, 2003 by $23 million. The increase was primarily due to increased pretax income in 2004. The effective tax rate for continuing operations was ~~32.5~~26.9 percent for the ~~first quarter of~~six months ended June 30, 2004, compared with ~~32.4~~24.7 percent for the ~~first~~same period in 2003. The increased rate in 2004 is due mainly to adjustments in the second quarter of ~~2003.~~2003, discussed above.

Critical Accounting Policies

Preparation of financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions, which all may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed. Item 7, Management’s Discussion and Analysis, in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2003, includes a list of accounting policies that are most significant to the portrayal of Xcel Energy’s financial condition and results,

and that require management’s most difficult, subjective or complex judgments. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions.

Financial Market Risks

Xcel Energy and its subsidiaries are exposed to market risks, including changes in commodity prices and interest rates, as disclosed in Management’s Discussion and Analysis in its Annual Report on Form 10-K for the year ended Dec. 31, 2003. Commodity price risks for Xcel Energy’s regulated subsidiaries are mitigated in most jurisdictions due to cost-based rate regulation. At ~~March 31,~~June 30, 2004, there were no material changes to the financial market risks that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2003, in Item 7A of Xcel Energy’s Annual Report on Form 10-K. Value-at-risk, energy trading and hedging information is provided below for informational purposes.

NSP-Minnesota maintains trust funds, as required by the ~~Nuclear Regulatory Commission,~~NRC, 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 and its subsidiaries use a value-at-risk (VaR) model to assess the market risk of their fixed price purchase and sales commitments, physical forward contracts and commodity derivative instruments. VaR for commodity contracts, assuming a five-day holding period for electricity and a two-day holding period for natural gas, for the three months ended ~~March 31,~~June 30, 2004, is as follows:


			Change from Period												Change from Period
	Period Ended		Ended										Period Ended		Ended
(Millions of Dollars)	March 31, 2004		Dec. 31, 2003		VaR Limit		Average		High		Low		June 30, 2004		March 31, 2004		VaR Limit		Average		High		Low
Electric Commodity Trading (1)	$	1.17	$	0.25	$	6.0	$	1.01	$	1.27	$	0.79	$	1.21	$	0.04	$	6.0	$	1.57	$	2.70	$	0.85

Xcel Energy and its subsidiaries engage in energy trading activities that are accounted for in accordance with SFAS No. 133, as amended. Xcel Energy and its subsidiaries make wholesale purchases and sales of electricity, natural gas and related energy products in order to optimize the value of their electric generating facilities and retail supply contracts. Xcel Energy also engages in a limited number of wholesale commodity transactions. Xcel Energy utilizes 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

Hedge Contracts

Futures/Forwards
(Thousands of Source of Maturity Less Maturity Maturity Maturity Greater Total Futures/
Dollars)
Fair Value
Than 1 Year
1 to 3 Years
4 to 5 Years
Than 5 Years
Forwards Fair Value
NSP-Minnesota 2 $ (113 ) $ (113 )
PSCo 1 474 474

Total Futures/Forwards Fair Value $ 361 $ 361

Options
(Thousands of Source of Maturity Less Maturity Maturity Maturity Greater Total Options Fair
Dollars)
Fair Value
Than 1 Year
1 to 3 Years
4 to 5 Years
Than 5 Years
Value
PSCo 2 $ 1,139 $ 1,066 $ 2,205

Total Options Fair Value $ 1,139 $ 1,066 $ 2,205


	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
PSCo		1	$	(612	)				$	(612	)
		2		3,792						3,792

Total Futures/Forwards Fair Value			$	3,180					$	3,180


	Options
	Source of		Maturity Less			Maturity		Maturity	Maturity Greater	Total Options Fair
(Thousands of Dollars)	Fair Value		Than 1 Year			1 to 3 Years		4 to 5 Years	Than 5 Years	Value
NSP-Minnesota		2	$	(813	)					$	(813	)
NSP-Wisconsin		2		(116	)						(116	)
PSCo		2		(4,003	)		1,022				(2,981	)

Total Options Fair Value			$	(4,932	)	$	1,022			$	(3,910	)

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

Interest Rate Risk

Xcel Energy and its subsidiaries are subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy’s policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.

At ~~March 31,~~June 30, 2004, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable debt would impact pretax interest expense by approximately ~~$1.1~~$4.4 million. See Note 8 to the consolidated financial statements for a discussion of Xcel Energy and its subsidiaries’ interest rate swaps.

Credit Risk

Xcel Energy and its subsidiaries are exposed to credit risk in the company’s risk management activities. Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations. Xcel Energy and its subsidiaries maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.

Xcel Energy and its subsidiaries conduct standard credit reviews for all counterparties. Xcel Energy employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. The credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

At ~~March 31,~~June 30, 2004, a 10-percent increase in prices would have resulted in a net mark-to-market increase in credit risk exposure of ~~$9.7~~$3.1 million, while a decrease of 10-percent would have resulted in a decrease of ~~$9.4~~$3.1 million.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows


							Six Months Ended
	Three Months Ended March 31,						June 30,
(Millions of Dollars)	2004			2003			2004			2003
Cash provided (used) by operating activities
Continuing operations	$	465		$	363		$	717		$	372
Discontinued operations		(77	)		(90	)		(381	)		202

Total	$	388		$	273		$	336		$	574

Cash provided by operating activities for continuing operations increased by ~~$102~~$345 million for the first ~~three~~six months of 2004, compared with the first ~~three~~six months of 2003. The increase was primarily due to ~~increased cash provided by working capital.~~an increase in the recovery of purchased natural gas and electric energy cost and the timing of payments related to these costs. The 2004 cash used in operating activities for discontinued operations decreased by ~~$13~~$583 million and includes the ~~initial~~full payment related to the NRG settlement agreement partially offset by the proceeds of the tax refund received by Xcel Energy from the carry back of its 2003 net operating loss that resulted from the write-off of its investment in NRG. ~~The operating activities for discontinued operations for the first three months of 2003 include operating cash flows of NRG, prior to deconsolidation which occurred in May 2003.~~


	Six Months Ended June 30,
(Millions of Dollars)	2004			2003
Cash provided (used) by investing activities
Continuing operations	$	(513	)	$	(472	)
Discontinued operations		11			107

Total	$	(502	)	$	(365	)

Cash used in investing activities for continuing operations ~~decreased~~increased by ~~$20~~$41 million for the first ~~three~~six months of 2004, compared with the first ~~three~~six months of 2003. This is largely due to increased utility capital expenditures partially offset by the availability of previously restricted ~~cash and lower other investments in 2004, partially offset by increased utility capital expenditures.~~cash. Cash provided by investing activities for discontinued operations decreased for the first ~~three~~six months of 2004 by ~~$151~~$96 million, compared with the first ~~three~~six months of 2003 due to receipt of the proceeds from the sale of Viking in January 2003.

The discontinued operations for the first six months of 2004 includes the proceeds from the sale of Xcel Argentina’s investment in CIESA, offset by the $15 million of the purchase price placed in escrow.


	Six Months Ended
	June 30,
(Millions of Dollars)	2004			2003
Cash provided (used) by financing activities
Continuing operations	$	(265	)	$	(292	)
Discontinued operations		—			(12	)

Total	$	(265	)	$	(304	)

Three Months Ended March 31,
(Millions of Dollars)
2004
2003
Cash provided (used) by financing activities

Continuing operations $ (222 ) $ (48 )
Discontinued operations — (25 )

Total $ (222 ) $ (73 )

Cash used in financing activities for continuing operations ~~increased~~decreased by approximately ~~$174~~$27 million for the first ~~three~~six months of 2004, compared with the first ~~three~~six months of 2003. The ~~increase~~decrease was primarily due to increased repayments of long-term debt in ~~2004,~~2003, as well as the proceeds of debt issued in 2003. Cash used in financing activities for discontinued operations decreased by approximately $25 million for the first three months of 2004, compared with the first three months of 2003 due to the divestiture of NRG in December 2003 and the absence of any of its cash flows in 2004.

Credit Facilities and Other Sources of Liquidity

Xcel Energy and Utility Subsidiary Credit Facilities- As of ~~April 23,~~July 20, 2004, Xcel Energy had the following credit facilities available to meet its liquidity needs:


(Millions of Dollars)
Company	Facility		Drawn*		Available		Cash		Liquidity		Maturity
(Millions of Dollars) Company												Facility		Drawn*		Available		Cash		Liquidity		Maturity
NSP-Minnesota	$	275	$	43	$	232	$	147	$	379	May-2004	$	300	$	39	$	261	$	19	$	280	May-2005
PSCo	$	350	$	15	$	335	$	3	$	338	May 2004
PSCo.												$	350	$	37	$	313	$	5	$	318	May 2005
SPS	$	125	$	15	$	110	$	0	$	110	Feb. 2005	$	125	$	61	$	64	$	10	$	74	Feb. 2005
Xcel Energy – Holding Company	$	400	$	19	$	381	$	348	$	729	Nov. 2005	$	400	$	48	$	352	$	3	$	355	Nov. 2005

Total	$	1,150	$	92	$	1,058	$	498	$	1,556		$	1,175	$	185	$	990	$	37	$	1,027

* Includes short-term borrowings and letters of credit

The liquidity table above reflects the payment of common dividends on ~~April~~July 20, ~~2004 and the repayment of $145 million of long-term debt at PSCo.~~2004.

NSP-Wisconsin has approval from the Wisconsin Public Service Commission to borrow up to $50 million in short-term debt from either external financial institutions or NSP-Minnesota. Currently, NSP-Wisconsin borrows on a short-term basis through an inter-company borrowing agreement with NSP-Minnesota. At ~~March 31,~~July 20, 2004, NSP-Wisconsin had $5.7 million of short-term borrowings from NSP-Minnesota and no short-term ~~borrowings outstanding and no cash.~~investments.

NSP-Minnesota replaced its $275 million secured credit facility, which expired in May 2004, with a $300 million unsecured, 364-day credit agreement. PSCo replaced its $350 million secured credit facility, which expired in May 2004, with a $350 million unsecured, 364-day credit agreement. Both new facilities include a term-out provision and ~~PSCo are currently~~one financial ratio covenant in the ~~process~~form of ~~renewing their 364-day revolving credit facilities. Both companies expect~~a debt to receive commitments from lenders on or around May 3, 2004 for the new 364-day revolving credit facilities. Closing of both facilities is expected to occur prior to the maturity of the existing credit facilities.total capitalization ratio.

~~Credit Ratings~~~~- Access to reasonably priced capital markets is dependent in part on credit agency reviews and ratings.~~

On April 19, 2004, Moody’s Investors Services, Inc. (Moody’s) upgraded the credit ratings of Xcel Energy’s senior unsecured debt by two notches. The credit ratings for the senior unsecured debt of NSP-Minnesota, NSP-Wisconsin and PSCo were upgraded by one notch. The credit ratings for SPS were affirmed at their current ratings. The Moody’s credit outlook for Xcel Energy and its operating companies is stable.

On March 12, 2004, Standard & Poor’s Ratings Service (Standard & Poor’s) affirmed the credit ratings for Xcel Energy, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS at their current ratings. The Standard & Poor’s credit outlook for Xcel Energy and its operating companies is stable.

2736

The following ratings reflect the views of Moody’s and Standard & Poor’s. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating company. As of April 20, 2004, the following represents the credit ratings assigned to various Xcel Energy companies:


~~Company~~	~~Credit Type~~	~~Moody’s~~	~~Standard & Poor’s~~
~~Xcel Energy~~	~~Senior Unsecured Debt~~	~~Baa1~~	~~BBB-~~
~~Xcel Energy~~	~~Preferred Stock~~	~~Baa3~~	~~BB+~~
~~Xcel Energy~~	~~Commercial Paper~~	~~N/A~~	A2

~~NSP-Minnesota~~	~~Senior Unsecured Debt~~	A3	~~BBB-~~
~~NSP-Minnesota~~	~~Senior Secured Debt~~	A2	~~BBB+~~
~~NSP-Minnesota~~	~~Commercial Paper~~	P2	A2

~~NSP-Wisconsin~~	~~Senior Unsecured Debt~~	A3	~~BBB~~
~~NSP-Wisconsin~~	~~Senior Secured Debt~~	A2	~~BBB+~~

~~PSCo~~	~~Senior Unsecured Debt~~	~~Baa1~~	~~BBB-~~
~~PSCo~~	~~Senior Secured Debt~~	A3	~~BBB+~~
~~PSCo~~	~~Commercial Paper~~	P2	A2

~~SPS~~	~~Senior Unsecured Debt~~	~~Baa1~~	~~BBB~~
~~SPS~~	~~Commercial Paper~~	P2	A2

Money Pool- In 2003, Xcel Energy received SEC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The utility money pool arrangement does not allow loans from the utility subsidiaries to the holding company. State regulatory commission approval of the arrangement is pending in several jurisdictions. The SEC approved short-term borrowing limits from the utility money pool are as follows:


NSP- Minnesota		$250 million
NSP- Wisconsin		$100 million
~~PSCo~~PSCo.		$250 million
SPS		$100 million

Xcel Energy expects to accumulate additional cash at the holding company level during 2004 from the lower federal income tax payments resulting from the expected tax benefit associated with its investment in NRG and from the receipt of operating company dividends. Restrictions imposed by state regulatory commissions, debt agreements and Public Utility Holding Company Act of 1935 limit the level of dividends the utility operating companies can pay to Xcel Energy.

Short-term debt and financial instruments are discussed in Note 7 to the consolidated financial statements.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Item 2, Management’s Discussion and Analysis — Market Risks.

Item 4. CONTROLS AND PROCEDURES

Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the chief executive officer (CEO) and chief financial officer (CFO), of the effectiveness of our disclosure controls and procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures are effective.

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

Part II — OTHER INFORMATION

Item 1. Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. See Notes 4, 5 and 6 of the consolidated financial statements in this Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 of Xcel Energy’s ~~2003~~Annual Report on Form 10-K for the year ended Dec. 31, 2003 and Note 17 of the consolidated financial statements in such Annual Report on Form 10-K for a description of certain legal proceedings presently pending. ~~There~~Except as set forth above, there are no new significant cases to report against Xcel Energy, and there have been no notable changes in the previously reported proceedings.

Item ~~2. Changes~~4. Submission of Matters to a Vote of Security Holders

Xcel Energy’s Annual Meeting of Shareholders was held on May 20, 2004, for the purpose of voting on the matters listed below. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934, and there were no solicitations in ~~Securities, Use~~opposition to management’s solicitations. All of ~~Proceeds and Issuer Purchases of Equity Securities~~

(d) Maximum Number
(or Approximate
(c) Total Number of Dollar
Shares Purchased as Value) of shares that
Part of Publicly May Yet Be Purchased
(a) Total Number of (b) Average Price Announced Plans or Under the Plans or
Period Shares Purchased Paid per Share Programs Programs
Jan. 1, 2004 – Jan. 31, 2004 — N/A — —
Feb. 1, 2004 – Feb. 29, 2004 600,000 $ 17.49 600,000 1,900,000
March 1, 2004 – March 31, 2004 1,200,000 $ 17.94 1,200,000 700,000

Total 1,800,000 1,800,000
management’s nominees for directors as listed in the proxy statement were elected. The voting results were as follows:

~~On Jan. 29, 2004, Xcel Energy announced that its~~

1. A proposal to elect six directors:


Election of Director	Shares Voted For		Withheld Authority
Richard H. Anderson		323,373,334		15,541,376
David A. Christensen		322,053,050		16,861,660
Richard C. Kelly		321,383,317		17,531,393
Ralph R. Peterson		322,690,990		16,223,720
Dr. Margaret R. Preska		306,347,154		32,567,556
W. Thomas Stephens		322,474,908		16,439,802

2. Proposal to amend the bylaws to eliminate the classification of terms of the board of directors:


Shares Voted For	Shares Voted Against		Shares Abstained
318,894,912		14,844,041		5,175,757

3. Proposal to approve the stock equivalent plan for non-employee directors ~~approved the repurchase~~ of up to 2.5 million shares of common stock to fulfill the requirements of an incentive plan. Purchases were authorized to be made in the open market pursuant to Rule 10b-18 or in privately negotiated block trades in compliance with Rule 10b-18 from time to time after Feb. 2, 2004. The plan had no expiration date. However, on March 25, 2004, Xcel ~~Energy announced that it had completed the repurchase and fulfilled the requirements of the plan.~~Energy:


Shares Voted For	Shares Voted Against		Shares Abstained		Broker Non-Votes
197,803,171		52,344,308		6,792,399		81,974,832

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

The following Exhibits are filed with this report:

*
* Indicates incorporation by reference.

3.01 Bylaws of Xcel Energy Inc., amended Feb. 25, 2004.
4.01 Credit Agreement between Public Service Company of Colorado; Bank One, NA; Wells Fargo Bank, National Association and other financial institutions, dated May 14, 2004.
4.02 Credit Agreement between Northern States Power Company (a Minnesota corporation); Wells Fargo Bank, National Association; Bank One, NA and other financial institutions, dated May 14, 2004.
10.01 * Stock purchase agreement between Xcel Energy Inc. and Black Hills Corp. dated Jan. 13, 2004, for the sale of Xcel Energy subsidiary Cheyenne Light, Fuel and Power Co. to Black Hills Corp. (Exhibit 99.01 to Form 8-k (file no. 001-03034) dated May 14, 2004.)
31.01 Principal Executive Officer’s and Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as ~~adopted~~ pursuant to Section adopted 302 of the Sarbanes-Oxley Act of 2002.

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

99.01 Statement pursuant to Private Securities Litigation Reform Act of 1995.

(b) Reports on Form 8-K

The following reports on Form 8-K were filed either during the three months ended ~~March 31,~~June 30, 2004, or between ~~March 31,~~June 30, 2004, and the date of this report:

~~Jan. 13, 2004 (filed Jan. 14, 2004) – Items 5 and Other Events and Financial Statements and Exhibits – Re: Agreement to sell Cheyenne Light, Fuel & Power Co.~~

~~Jan. 28, 2004 (filed Jan. 28, 2004) – Items 7 and 12 Exhibits and Results of Operations and Financial Statements – Re: Xcel Energy Earnings Release.~~

~~Jan. 28, 2004 (filed Jan. 28, 2004) – Items 5 and 7 Other Events and Financial Statements and Exhibits – Re: e prime settlement agreement with U.S. Commodity Futures Trading Commission.~~

Feb. 11, 2004 (filed Feb. 11, 2004) – Items 7 and 12 Exhibits and Results of Operations and Financial Statements – Re: Xcel Energy presentation to the Edison Electric Institute International Financial Conference on Feb. 16, 2004.

~~March 1, 2004 (filed March 1, 2004) – Items 5 and 7 Other Events and Financial Statements and Exhibits – Re: Xcel Energy 2003 Audited Financial Statements.~~

March 24, 2004 (filed March 24, 2004) – Items 7 and 12 Exhibits and Results of Operations and Financial Statements – Re: Xcel Energy presentation to the Morgan Stanley Global Electricity & Energy Conference on March 24, 2004.

April 28, 2004 (filed April 28, 2004) – Items 7 and 12 Exhibits and Results of Operations and Financial Statements – Re: Xcel Energy’s ~~first~~earnings release dated April 28, 2004.

May 14, 2004 (filed May 14, 2004) – Items 5 and 7 Other Events and Financial Statements and Exhibits – Re: Cheyenne Light, Fuel and Power Purchase Agreement.

June 3, 2004 (filed June 14, 2004) – Item 5 Other Events – Re: Sale of Xcel Energy Argentina.

June 16, 2004 (filed June 16, 2004) – Items 7 and 12 Exhibits and Results of Operations and Financial Statements – Re: Presentation to the Deutsche Bank Electric Power Conference.

July 28, 2004 (filed July 28, 2004) – Items 7 and 12 Exhibits and Results of Operations and Financial Statements – Re: Xcel Energy’s second quarter 2004 earnings release.

3038

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.


		XCEL ENERGY INC. (Registrant)
	/s/ TERESA S. MADDEN
	Teresa S. Madden
	Vice President and Controller


		~~(Registrant)~~

		~~/s/ TERESA S. MADDEN~~

		~~Teresa S. Madden~~
		~~Vice President and Controller~~

		/s/ BENJAMIN G.S. FOWKE III

		Benjamin G.S. Fowke III
		Vice President and Chief Financial Officer
		~~and Treasurer~~
~~May 4, 2004~~

31August 4, 2004


(Thousands of dollars)	March 31, 2004		Dec. 31, 2003		June 30, 2004		Dec. 31, 2003
Cash	$	40,906	$	36,517	$	12,234	$	36,517
Restricted cash						15,000		—
Trade receivables — net		30,976		50,887		12,261		50,887
Deferred income tax benefits		131,171		580,626		170,064		580,626
Other current assets		32,544		46,480		16,993		46,480

Current assets held for sale		235,597		714,510	$	226,552	$	714,510

Property, plant and equipment — net		116,913		120,759	$	97,694	$	120,759
Deferred income tax benefits		437,512		314,670		425,186		314,670
Other noncurrent assets		14,295		12,943		5,610		12,943

Noncurrent assets held for sale		568,720		448,372	$	528,490	$	448,372

Current portion of long-term debt		—		—	$	—	$	—
Accounts payable — trade		27,833		56,812		16,254		56,812
NRG settlement payments		352,000		752,000		—		752,000
Other current liabilities		8,323		23,280		8,789		23,280

Current liabilities held for sale		388,156		832,092	$	25,043	$	832,092

Long-term debt		24,800		25,000	$	24,800	$	25,000
Minority interest		5,449		5,363		—		5,363
Other noncurrent liabilities		26,491		24,919		26,218		24,919

Noncurrent liabilities held for sale	$	56,740	$	55,282	$	51,018	$	55,282


	3 months ended
	March 31,						Three months ended June 30,						Six months ended June 30,
(Thousands of Dollars)	2004			2003			2004			2003			2004			2003
Allowance for equity funds used during construction		8,456			3,060		$	8,228		$	9,021		$	16,684		$	12,081
Interest income	$	3,129		$	4,889			2,993			4,902			6,122			9,791
Equity income (loss) in unconsolidated affiliates		846			(5,622	)		97			1,355			943			(4,267	)
Other nonoperating income		489			1,704			3,014			780			3,503			2,484
Minority interest income		17			—			(24	)		—			(7	)		—
Interest expense on corporate-owned life insurance and other		(5,475	)		(4,836	)		(6,961	)		(6,057	)		(12,436	)		(10,893	)

Total interest and other income, net of nonoperating expenses	$	7,462		$	(805	)	$	7,347		$	10,001		$	14,809		$	9,196


	Six months ended June 30, 2004							Six months ended June 30, 2003
						Per share							Per share
(Amounts in thousands, except per share amounts)	Income			Shares		Amount		Income			Shares		Amount
Income from continuing operations	$	225,475						$	180,625
Less: Dividend requirements on preferred stock		(2,120	)						(2,120	)

Basic earnings per share:
Income from continuing operations		223,355			398,900	$	0.56		178,505			398,716	$	0.45
Effect of dilutive securities:
$230 million convertible debt		5,849			18,654				5,606			18,654
$57.5 million convertible debt		1,462			4,663				—			—
Convertible debt option		—			—				—			237
Options		—			16				—			9

Diluted earnings per share:
Income from continuing operations and assumed conversions	$	230,666			422,233	$	0.54	$	184,111			417,616	$	0.44


	Three months ended March 31,
	2004			2003			2004			2003			Three months ended June 30,
							Postretirement Health						2004			2003			2004			2003
(Thousands of dollars)	Pension Benefits						Care Benefits												Postretirement Health
Xcel Energy Inc.													Pension Benefits						Care Benefits
Service cost	$	16,350		$	18,943		$	1,625		$	1,328		$	13,124		$	14,791		$	1,425		$	1,617
Interest cost		38,175			45,190			12,900			11,747			44,499			40,186			13,402			14,466
Expected return on plan assets		(72,225	)		(82,287	)		(5,275	)		(5,624	)		(79,307	)		(78,741	)		(6,351	)		(5,468	)
Amortization of transition (asset) obligation		(2	)		(500	)		3,700			3,432			(2	)		(498	)		3,590			4,281
Amortization of prior service cost (credit)		7,601			7,976			(550	)		(706	)		7,405			6,148			(540	)		(60	)
Amortization of net (gain) loss		(5,141	)		(11,382	)		5,550			2,878			(2,577	)		(11,038	)		5,276			4,827

Net periodic benefit cost (credit)		(15,242	)		(22,060	)	$	17,950		$	13,055			(16,858	)		(29,152	)		16,802			19,663
Credits not recognized due to the effects of regulation		10,177			12,084			—			—
Settlements and curtailments														703			1,309			—			(2,128	)
Costs not recognized due to the effects of regulation														8,568			13,461			—			—
Additional cost recognized due to the effects of regulation		—			—			973			973			—			—			972			965

Net benefit cost (credit) recognized for financial reporting	$	(5,065	)	$	(9,976	)	$	18,923		$	14,028		$	(7,587	)	$	(14,382	)	$	17,774		$	18,500


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


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


PART I — FINANCIAL INFORMATION
	Item 1. Financial Statements
		CONSOLIDATED STATEMENTS OF OPERATIONS
		CONSOLIDATED STATEMENTS OF CASH FLOWS
		CONSOLIDATED BALANCE SHEETS
		CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY AND OTHER COMPREHENSIVE INCOME
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
	Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	Item 4. CONTROLS AND PROCEDURES
Part II — OTHER INFORMATION
	Item 1. Legal Proceedings
	Item ~~2. Changes in Securities, Use~~4. Submission of ~~Proceeds and Issuer Purchases~~Matters to a Vote of ~~Equity Securities~~Security Holders
	Item 6. Exhibits and Reports on Form 8-K
SIGNATURES
~~Certifications~~Bylaws
Credit Agreement
Credit Agreement
Certification Pursuant to Section 302
~~Certifications~~Certification Pursuant to Section 906
Statement Pursuant to Private Litigation


	Three Months Ended March 31,
(Thousands of Dollars, Except Per Share Data	2004		2003
Operating revenues:
Electric utility	$	1,469,424	$	1,365,378
Natural gas utility		762,808		654,272
Electric trading margin		4,176		(1,034	)
Nonregulated and other		54,177		56,941

Total operating revenues		2,290,585		2,075,557
Operating expenses:
Electric fuel and purchased power – utility		678,693		592,151
Cost of natural gas sold and transported – utility		594,252		474,211
Cost of sales – nonregulated and other		28,554		34,370
Other operating and maintenance expenses – utility		393,645		377,502
Other operating and maintenance expenses – nonregulated		20,652		23,560
Depreciation and amortization		175,771		191,153
Taxes (other than income taxes)		84,895		80,700

Total operating expenses		1,976,462		1,773,647

Operating income		314,123		301,910
Interest and other income (expense), net (see Note 9)		7,462		(805	)
Interest charges and financing costs:
Interest charges – net of amounts capitalized (includes other financing costs of $7,426 and $6,249, respectively)		107,742		105,076
Distributions on redeemable preferred securities of subsidiary trusts		—		9,586

Total interest charges and financing costs		107,742		114,662
Income from continuing operations before income taxes		213,843		186,443
Income taxes		69,545		60,477

Income from continuing operations		144,298		125,966
Income from discontinued operations, net of tax (see Note 2)		5,613		14,046

Net income		149,911		140,012
Dividend requirements on preferred stock		1,060		1,060

Earnings available to common shareholders	$	148,851	$	138,952

Weighted average common shares outstanding (thousands):
Basic		398,583		398,714
Diluted		421,921		417,368
Earnings per share – basic:
Income from continuing operations	$	0.36	$	0.31
Discontinued operations		0.01		0.04

Earnings per share – basic	$	0.37	$	0.35

Earnings per share – diluted:
Income from continuing operations	$	0.35	$	0.31
Discontinued operations		0.01		0.03

Earnings per share – diluted	$	0.36	$	0.34

•		~~Tax Matters — See Note 4 to the accompanying consolidated financial statements for discussion of exposures regarding the tax deductibility of corporate-owned life insurance loan interest; and~~

•		~~Guarantees — See Note 7 to the accompanying consolidated financial statements for discussion of exposures under various guarantees.~~

•		Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;

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

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

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

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

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

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

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

•		Increased competition in the utility industry or additional competition in the markets served by Xcel Energy and its subsidiaries;

•		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; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

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

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

•		Social attitudes regarding the utility and power industries;

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

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

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

•		Risks associated with implementations of new technologies;

•		Other business or investment considerations that may be disclosed from time to time in Xcel Energy’s SEC filings or in other publicly disseminated written documents; and

•		The other risk factors listed from time to time by Xcel Energy in reports filed with the SEC, including Exhibit 99.01 to this report on Form 10-Q for the quarter ended ~~March 31,~~June 30, 2004.

•		regulated utility subsidiaries, operating in the electric and natural gas segments; and

•		several nonregulated subsidiaries and the holding company, where corporate financing activity occurs.

•		the regulated natural gas businesses Viking and BMG, which were sold in 2003;

•		the regulated utility business of CLF&P for which a sale agreement was entered into in early 2004;

•		NRG, which emerged from bankruptcy in late 2003, at which time Xcel Energy divested its ownership interest in NRG; and

•		the nonregulated subsidiaries Xcel Energy International and e prime, which were classified as held for sale in late 2003 based on the decision to divest them.


	Three months ended
	March 31,
Contribution to Earnings (Millions of dollars)	2004			2003
GAAP income (loss) by segment
Regulated electric utility segment income — continuing operations	$	105.3		$	86.0
Regulated natural gas utility segment income — continuing operations		48.2			55.3
Other utility results (a)		4.3			3.5

Total utility segment income — continuing operations		157.8			144.8
Other nonregulated results and holding company costs (a)		(13.5	)		(18.8	)

Total income — continuing operations		144.3			126.0
Regulated utility income — discontinued operations		0.8			22.8
NRG loss — discontinued operations		—			(11.6	)
Other nonregulated income — discontinued operations		4.8			2.8

Total income — discontinued operations		5.6			14.0

Total GAAP income	$	149.9		$	140.0


	Earnings per Share Increase (Decrease)
	2004 vs. Normal			2003 vs. Normal		2004 vs. 2003
Three months ended March 31	$	(0.01	)	$	0.00	$	(0.01	)

•		During the second quarter of 2003, $10 million of depreciation expense was recorded for renewable development fund costs, which are largely recovered through NSP-Minnesota’s fuel clause mechanism,

•		The Minnesota legislature authorized during 2003 additional spent nuclear fuel storage at the Prairie Island nuclear plant. In December 2003, the MPUC extended the authorized useful lives of the two generating units at the Prairie Island nuclear plant retroactive to Jan. 1, 2003. The 2003 annual reduction was recorded in the fourth quarter of 2003. Annual depreciation expense for 2004 is expected to be approximately $18 million lower than 2003, due to a change in the decommissioning accruals resulting from a related MPUC order and

•		Effective July 1, 2003, the CPUC lengthened the depreciable lives of certain electric utility plant at PSCo as a part of the general Colorado rate case, which will reduce annual depreciation expense by $20 million.


	Futures/Forwards													Futures/Forwards
(Thousands of	Source of		Maturity Less			Maturity			Maturity	Maturity Greater	Total Futures/
Dollars)	Fair Value		Than 1 Year			1 to 3 Years			4 to 5 Years	Than 5 Years	Forwards Fair Value
														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	$	(226	)						$	(226	)		1	$	(174	)						$	(174	)
		2		2,258			488					2,746			2		1,231			320					1,551
PSCo		1		1,349								1,349			1		887								887
		2		(641	)		(312	)				(953	)		2		650			(798	)				(148	)

Total Futures/Forwards Fair Value			$	2,740		$	176				$	2,916				$	2,594		$	(478	)			$	2,116


							(d) Maximum Number
							(or Approximate
					(c) Total Number of		Dollar
					Shares Purchased as		Value) of shares that
					Part of Publicly		May Yet Be Purchased
	(a) Total Number of		(b) Average Price		Announced Plans or		Under the Plans or
Period	Shares Purchased		Paid per Share		Programs		Programs
Jan. 1, 2004 – Jan. 31, 2004		—		N/A		—		—
Feb. 1, 2004 – Feb. 29, 2004		600,000	$	17.49		600,000		1,900,000
March 1, 2004 – March 31, 2004		1,200,000	$	17.94		1,200,000		700,000

Total		1,800,000				1,800,000

3.01		Bylaws of Xcel Energy Inc., amended Feb. 25, 2004.

4.01		Credit Agreement between Public Service Company of Colorado; Bank One, NA; Wells Fargo Bank, National Association and other financial institutions, dated May 14, 2004.

4.02		Credit Agreement between Northern States Power Company (a Minnesota corporation); Wells Fargo Bank, National Association; Bank One, NA and other financial institutions, dated May 14, 2004.

10.01	*	Stock purchase agreement between Xcel Energy Inc. and Black Hills Corp. dated Jan. 13, 2004, for the sale of Xcel Energy subsidiary Cheyenne Light, Fuel and Power Co. to Black Hills Corp. (Exhibit 99.01 to Form 8-k (file no. 001-03034) dated May 14, 2004.)

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

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

99.01		Statement pursuant to Private Securities Litigation Reform Act of 1995.