XCEL ENERGY INC - 10-Q Quarterly Report

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(Thousands of Dollars, Except Per Share Data)

	Three Months Ended Sept. 30,							Nine Months Ended Sept. 30,
	2004				2003			2004			2003
Operating revenues:
Electric utility	$	1,775,860			$	1,754,514		$	4,721,518		$	4,494,219
Natural gas utility	191,096				178,731			1,227,269			1,099,744
Electric trading margin	8,410				10,837			13,528			15,451
Nonregulated and other	33,246				57,518			123,583			163,420
Total operating revenues	2,008,612				2,001,600			6,085,898			5,772,834

Operating expenses:
Electric fuel and purchased power – utility	888,845				814,446			2,290,560			2,045,939
Cost of natural gas sold and transported – utility	111,185				100,763			891,778			745,968
Cost of sales – nonregulated and other	14,641				46,470			65,521			108,897
Other operating and maintenance expenses – utility	378,912				383,252			1,165,447			1,139,274
Other operating and maintenance expenses – nonregulated	13,814				16,571			39,668			53,334
Depreciation and amortization	176,903				186,979			520,766			573,147
Taxes (other than income taxes)	86,255				84,251			253,746			246,306
Special charges	—				2,980			—			13,416
Total operating expenses	1,670,555				1,635,712			5,227,486			4,926,281
Operating income	338,057				365,888			858,412			846,553

Interest and other income – net of other expense (see Note 9)	7,347				20,623			22,199			29,864

Interest charges and financing costs:
Interest charges – net of amounts capitalized (includes other financing costs of $6,354, $8,436, $20,786 and $24,624, respectively)	105,003				104,318			317,984			318,871
Distributions on redeemable preferred securities of subsidiary trusts	—				2,621			—			21,773
Total interest charges and financing costs	105,003				106,939			317,984			340,644
Income from continuing operations before income taxes	240,401				279,572			562,627			535,773
Income taxes	74,218				94,924			162,287			162,863
Income from continuing operations	166,183				184,648			400,340			372,910
Income (loss) from discontinued operations – net of tax (see Note 2)	(119,463			)	102,847			(117,404		)	(227,965		)
Net income	46,720				287,495			282,936			144,945
Dividend requirements on preferred stock	1,060				1,060			3,180			3,180
Earnings available to common shareholders	$		45,660		$		286,435	$	279,756		$	141,765

Weighted average common shares outstanding (thousands):
Basic	399,746				398,751			399,184			398,728
Diluted	423,078				418,128			422,517			417,798
Earnings per share – basic:
Income from continuing operations	$		0.41		$		0.46	$	0.99		$	0.93
Income (loss) from discontinued operations	(0.30			)	0.26			(0.29		)	(0.57		)
Earnings per share – basic	$		0.11		$		0.72	$	0.70		$	0.36
Earnings per share – diluted:
Income from continuing operations	$		0.40		$		0.44	$	0.97		$	0.91
Income (loss) from discontinued operations	(0.28			)	0.25			(0.28		)	(0.55		)
Earnings per share – diluted	$		0.12		$		0.69	$	0.69		$	0.36

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

	Nine Months Ended Sept. 30,
	2004				2003
Operating activities:
Net income	$	282,936			$	144,945
Add loss from discontinued operations	117,404				227,965
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	546,203				594,193
Nuclear fuel amortization	33,691				32,982
Deferred income taxes	91,685				80,087
Amortization of investment tax credits	(9,166			)	(9,330		)
Allowance for equity funds used during construction	(24,084			)	(18,140		)
Undistributed equity in earnings of unconsolidated affiliates	1,129				(1,276		)
Unrealized loss on derivative financial instruments	4,303				37,990
Change in accounts receivable	14,468				(82,497		)
Change in inventories	(51,895			)	(11,391		)
Change in other current assets	(28,985			)	(148,532		)
Change in accounts payable	(33,151			)	(43,585		)
Change in other current liabilities	(19,217			)	112,368
Change in other noncurrent assets	(26,399			)	(55,282		)
Change in other noncurrent liabilities	48,620				(72,687		)
Operating cash flows (used in) provided by discontinued operations	(316,110			)	215,313
Net cash provided by operating activities	631,432				1,003,123

Investing activities:
Utility capital/construction expenditures	(856,506			)	(637,332		)
Allowance for equity funds used during construction	24,084				18,140
Investments in external decommissioning fund	(60,435			)	(42,669		)
Nonregulated capital expenditures and asset acquisitions	(964			)	(31,283		)
Restricted cash	44,242				23,000
Other investments — net	11,382				(15,811		)
Investing cash flows provided by discontinued operations	11,252				94,729
Net cash used in investing activities	(826,945			)	(591,226		)

Financing activities:
Short-term borrowings – net	13,437				(104,547		)
Proceeds from issuance of long-term debt	—				1,381,984
Proceeds from (repayments of) borrowing on senior unsecured credit facility	139,000				(269,000		)
Repayment of long-term debt, including reacquisition premiums	(150,727			)	(1,003,965		)
Repurchase of stock	(32,023			)	—
Proceeds from issuance of common stock	4,470				833
Dividends paid	(235,650			)	(227,455		)
Financing cash flows used in discontinued operations	(200			)	(10,267		)
Net cash used in financing activities	(261,693			)	(232,417		)

Net (decrease) increase in cash and cash equivalents	(457,206			)	179,480
Net decrease in cash and cash equivalents – discontinued operations	(22,605			)	(6,390		)
Net increase in cash and cash equivalents – adoption of FIN No.46	2,303				—
Cash and cash equivalents at beginning of year	568,283				484,578
Cash and cash equivalents at end of quarter	$		90,775		$	657,668
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$		287,088		$	434,772
Cash paid for income taxes (net of refunds received)	$		(339,700	)	$	32,261

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

	Sept. 30, 2004			Dec. 31, 2003
ASSETS
Current assets:
Cash and cash equivalents	$	90,775		$	568,283
Restricted cash	150			37,363
Accounts receivable – net of allowance for bad debts of $32,867 and $30,899, respectively	631,981			646,638
Accrued unbilled revenues	362,302			367,005
Materials and supplies inventories – at average cost	166,388			162,140
Fuel inventory – at average cost	66,369			59,706
Natural gas inventories – at average cost as of Sept. 30, 2004; replacement cost in excess of LIFO: $73,197 as of Dec. 31, 2003 (see Note 1)	214,332			140,636
Recoverable purchased natural gas and electric energy costs	147,448			217,473
Derivative instruments valuation – at market	105,397			93,063
Prepayments and other	127,189			110,876
Current assets held for sale and related to discontinued operations	258,465			728,056
Total current assets	2,170,796			3,131,239
Property, plant and equipment, at cost:
Electric utility plant	17,899,094			17,242,636
Natural gas utility plant	2,581,303			2,442,994
Common utility and other property	1,505,078			1,217,461
Construction work in progress	836,953			917,530
Total property, plant and equipment	22,822,428			21,820,621
Less accumulated depreciation	(9,028,248		)	(8,605,082		)
Nuclear fuel – net of accumulated amortization: $1,135,623 and $1,101,932, respectively	71,898			80,289
Net property, plant and equipment	13,866,078			13,295,828
Other assets:
Investments in unconsolidated affiliates	72,328			124,462
Nuclear decommissioning fund and other investments	921,579			842,832
Regulatory assets	920,885			879,320
Derivative instruments valuation – at market	637,326			429,531
Prepaid pension asset	624,641			566,568
Other	185,147			206,870
Noncurrent assets held for sale and related to discontinued operations	659,801			728,730
Total other assets	4,021,707			3,778,313
Total assets	$	20,058,581		$	20,205,380

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	20,630		$	159,955
Short-term debt	72,000			58,563
Accounts payable	744,788			774,336
Taxes accrued	200,614			193,895
Dividends payable	84,038			75,866
Derivative instruments valuation – at market	229,191			153,467
Other	364,296			411,435
Current liabilities held for sale and related to discontinued operations	86,260			843,549
Total current liabilities	1,801,817			2,671,066
Deferred credits and other liabilities:
Deferred income taxes	2,028,715			1,991,483
Deferred investment tax credits	146,154			155,629
Regulatory liabilities	1,686,836			1,559,779
Derivative instruments valuation – at market	524,346			388,743
Asset retirement obligations	1,074,054			1,024,529
Customer advances	292,641			211,046
Minimum pension liability	15,459			54,647
Benefit obligations and other	387,502			310,355
Noncurrent liabilities held for sale and related to discontinued operations	81,298			72,549
Total deferred credits and other liabilities	6,237,005			5,768,760
Minority interest in subsidiaries	3,630			281
Commitments and contingent liabilities (see Note 6)
Capitalization:
Long-term debt	6,558,791			6,493,853
$400-million, 5-year, senior unsecured credit facility	139,000			—
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 – 399,912,553; 2003 – 398,964,724	5,213,358			5,166,440
Total liabilities and equity	$	20,058,581		$	20,205,380

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

AND OTHER COMPREHENSIVE INCOME

(UNAUDITED)

(Thousands)

	Common Stock Issued
Three months ended Sept. 30, 2004 and 2003	Number of Shares	Par Value		Capital in Excess of Par Value		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity

Balance at June 30, 2003	398,732	$	996,830	$	3,888,803	$	(244,552	)	$	(257,064	)	$	4,384,017
Net income						287,495						287,495
Currency translation adjustments									(6,062		)	(6,062		)
After-tax unrealized and realized gains related to derivatives – net (see Note 8)									48,057			48,057
Unrealized gain on marketable securities									208			208
Comprehensive income for the period												329,698
Dividends declared:
Cumulative preferred stock of Xcel Energy						—						—
Common stock						—						—
Issuances of common stock – net proceeds	47	118		497								615
Balance at Sept. 30, 2003	398,779	$	996,948	$	3,889,300	$	42,943		$	(214,861	)	$	4,714,330

Balance at June 30, 2004	399,395	$	998,488	$	3,895,313	$	445,095		$	(81,198	)	$	5,257,698
Net income						46,720						46,720
Currency translation adjustment									(37		)	(37		)
After-tax unrealized and realized losses related to derivatives – net (see Note 8)									(15,763		)	(15,763		)
Unrealized loss on marketable securities									(36		)	(36		)
Comprehensive income for the period												30,884
Dividends declared:
Cumulative preferred stock of Xcel Energy						(1,060		)				(1,060		)
Common stock						(82,978		)				(82,978		)
Issuances of common stock – net proceeds	517	1,292		7,522								8,814
Balance at Sept. 30, 2004	399,912	$	999,780	$	3,902,835	$	407,777		$	(97,034	)	$	5,213,358

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

AND OTHER COMPREHENSIVE INCOME

(UNAUDITED)

(Thousands)

	Common Stock Issued
Nine months ended Sept. 30, 2004 and 2003	Number of Shares		Par Value			Capital in Excess of Par Value				Retained Earnings (Deficit)				Accumulated Other Comprehensive Income (Loss)				Total Stockholders’ Equity

Balance at Dec. 31, 2002	398,714		$	996,785		$	4,038,151			$	(100,942		)	$		(269,010	)	$		4,664,984
Net income										144,945								144,945
Currency translation adjustments														91,299				91,299
After-tax unrealized and realized losses related to derivatives – net (see Note 8)														(12,532			)	(12,532				)
Minimum pension liability														(24,837			)	(24,837				)
Unrealized gain on marketable securities														219				219
Comprehensive income for the period																		199,094
Dividends declared:
Cumulative preferred stock of Xcel Energy						(1,060			)	(1,060			)					(2,120				)
Common stock						(148,461			)									(148,461				)
Issuances of common stock – net	65		163			670												833
Balance at Sept. 30, 2003	398,779		$	996,948		$	3,889,300			$	42,943			$		(214,861	)	$			4,714,330

Balance at Dec. 31, 2003	398,965		$	997,412		$		3,890,501		$		368,663		$	(90,136		)	$	5,166,440
Net income										282,936								282,936
Currency translation adjustments														(1,158			)	(1,158				)
After-tax unrealized and realized losses related to derivatives – net (see Note 8)														(5,796			)	(5,796				)
Unrealized gain on marketable securities														56				56
Comprehensive income for the period																		276,038
Dividends declared:
Cumulative preferred stock of Xcel Energy										(3,180			)					(3,180				)
Common stock										(240,642			)					(240,642				)
Issuances of common stock – net	2,747		6,868			39,857												46,725
Repurchase for restricted stock	(1,800	)	(4,500		)	(27,523			)									(32,023				)
Balance at Sept. 30, 2004	399,912		$	999,780		$		3,902,835		$		407,777		$	(97,034		)	$	5,213,358

See Notes to Consolidated Financial Statements

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 Co. (CLF&P). As a result of this agreement, CLF&P is classified as held for sale. The sale is pending SEC approval under the Public Utility Holding Company Act 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 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

Seren Innovations, Inc. – On Sept. 27, 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of, Xcel Energy’s broadband communications services business operated through its wholly owned, subsidiary Seren Innovations, Inc. (Seren). Seren delivers cable television, high-speed Internet and telephone service over an advanced network to approximately 45,000 customers in St. Cloud, Minn., and Concord and Walnut Creek, Calif. Xcel Energy management determined that the continued ownership of Seren was not consistent with the strategy of building the core utility operations. Management expects to complete the sale in the first quarter of 2005.

As a result of the decision, Seren is accounted for as discontinued operations. An after-tax impairment charge, including disposition costs of $112 million, or 27 cents per share, was recorded in the third quarter based on an estimated sales price of $2,400 per customer.

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, inc. (e prime). Xcel Energy International’s operations primarily included 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 exit of all business conducted by e prime was completed in 2004. Also during 2004, Xcel Energy completed the sale of Argentina subsidiaries of Xcel Energy International. For sales in the first three quarters of 2004, the total sales price was estimated at approximately $23 million, including certain adjustments subject to finalization. Approximately $15 million of the sales price has been placed in escrow, which is expected to remain in place until the first quarter of 2005, to support Xcel Energy’s customary indemnity obligations under the sales agreement. In addition to the sales price, Xcel Energy also received approximately $21 million at closing as a redemption of its capital investment. The sale resulted in an after-tax gain of $3.8 million through the third quarter of 2004. The gain includes the realization of $6.5 million of tax benefits related to the now-realizable tax loss from disposition of Xcel Energy International assets.

On Oct. 25, 2004, Xcel Energy closed on the sale of the stock of Electrica del Sur S.A. and its primary asset, Energia del Sur S.A. to Patagonia Energy Ltd. Its primary asset is a 76 megawatt gas-fired facility in Argentina. The sale is expected to result in a pretax gain of approximately

$2.5 million in the fourth quarter of 2004. Xcel Energy International is in the process of closing its remaining assets and operations and expects to exit the businesses held for sale during 2004.

Tax Benefits Related to Investment in NRG - With NRG’s emergence from bankruptcy in December 2003, Xcel Energy divested its ownership interest in NRG and reported a loss deduction in its 2003 tax return. These tax benefits, related to Xcel Energy’s investment in discontinued NRG operations, are also reported as discontinued operations. In late August 2003, Xcel Energy determined that the tax basis in NRG was greater than originally estimated and that additional state tax benefits were available related to its investment in NRG. Based on revised estimates, Xcel Energy recorded $105 million, or 25 cents per share, of additional tax benefits in the third quarter of 2003.

Summarized Financial Results of Discontinued Operations

(Thousands of Dollars)	Utility Segments				NRG Segment			All Other				Total
Three months ended Sept. 30, 2004
Operating revenue	$	23,155			$	—		$		11,005		$		34,160
Operating and other expenses	(22,429			)	—			(196,055			)	(218,484			)
Other income (expenses)–net	—				—			(6,035			)	(6,035			)
Pretax income (loss) from operations of discontinued components	726				—			(191,085			)	(190,359			)
Income tax benefit (expense)	(276			)	—			71,172				70,896
Net income (loss) from discontinued operations	$	450			$	—		$	(119,913		)	$	(119,463		)
Three months ended Sept. 30, 2003
Operating revenue	$		10,108		$		—	$	46,016			$	56,124
Operating and other expenses	(9,560			)	—			(52,193			)	(61,753			)
Other income (expenses)–net	—				—			959				959
Pretax income (loss) from operations of discontinued components	548				—			(5,218			)	(4,670			)
Income tax benefit (expense)	(124			)	—			107,641				107,517
Net income from discontinued operations	$		424		$		—	$	102,423			$	102,847

(Thousands of Dollars)	Utility Segments				NRG Segment				All Other					Total
Nine months ended Sept. 30, 2004
Operating revenue	$	68,399			$	—			$			78,145		$		146,544
Operating and other expenses	(65,511			)	—				(271,463				)	(336,974			)
Other income (expenses)–net	—				—				(5,550				)	(5,550			)
Pretax income (loss) from operations of discontinued components	2,888				—				(198,868				)	(195,980			)
Income tax benefit (expense)	(1,004			)	—				79,580					78,576
Net income (loss) from discontinued operations	$	1,884			$	—			$	(119,288			)	$	(117,404		)
Nine months ended Sept. 30, 2003
Operating revenue	$		37,513		$		—		$		164,974			$	202,487
Operating and other expenses	(33,284			)	—				(179,696				)	(212,980			)
Other income (expenses)–net	—				—				663					663
Equity in NRG losses	—				(362,161			)	—					(362,161			)
Pretax income (loss) from operations of discontinued components	4,229				(362,161			)	(14,059				)	(371,991			)
Income tax benefit (expense)	(1,519			)	—				124,546					123,027
Income (loss) from operations of discontinued components	2,710				(362,161			)	110,487					(248,964			)
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	$		23,709		$		(362,161	)	$	110,487				$	(227,965		)

The major classes of assets and liabilities held for sale and related to discontinued operations are as follows:

(Thousands of Dollars)	Sept. 30, 2004		Dec. 31, 2003
Cash	$	17,390	$		39,995
Restricted cash	15,000		—
Trade receivables — net	14,236		55,057
Deferred income tax benefits	180,947		580,626
Other current assets	30,892		52,378
Current assets held for sale	$	258,465	$	728,056
Property, plant and equipment — net	$	192,150	$		399,271
Deferred income tax benefits	451,261		314,670
Other noncurrent assets	16,390		14,789
Noncurrent assets held for sale	$	659,801	$		728,730
Current portion of long-term debt	$	—	$		—
Accounts payable — trade	24,430		68,056
NRG settlement payments	—		752,000
Other current liabilities	61,830		23,493
Current liabilities held for sale	$	86,260	$	843,549
Long-term debt	$	24,800	$	25,000
Minority interest	—		5,363
Other noncurrent liabilities	56,498		42,186
Noncurrent liabilities held for sale	$	81,298	$	72,549

3. NRG Bankruptcy Settlement

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 payment was paid on May 28, 2004. Xcel Energy met these cash requirements with cash on hand, including tax refund proceeds associated with the NRG bankruptcy, and/or borrowings under its revolving credit facility.

4. Tax Matters — Corporate-Owned Life Insurance (COLI)

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

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

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

Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2004, would reduce earnings by an estimated $317 million. In the third quarter of 2004, Xcel Energy received formal notification that the IRS will seek penalties. If penalties (plus associated interest) are also included, the total exposure through Dec. 31, 2004, increases to approximately $380 million. At Sept. 30, 2004, Xcel Energy estimates its annual earnings for 2004 would be reduced by $35 million, after tax, which represents 8 cents per share, if COLI interest expense deductions were no longer available.

Accounting for Uncertain Tax Positions – In late July 2004, the FASB discussed potential changes or clarifications in the criteria for recognition of tax benefits, which may result in raising the threshold for recognizing tax benefits which have some degree of uncertainty. The FASB has not issued any proposed guidance, but has indicated that it expects to in the fourth quarter of 2004. Xcel Energy is unable to determine the impact or timing of any potential accounting changes required by the FASB, but such changes could have a material financial impact.

5. Rates and Regulation

Market Based Rate Authority Rule Proposal - On April 14, 2004, the Federal Energy Regulatory Commission (FERC) initiated a new proceeding on future market-based rates authorizations and issued interim requirements for FERC jurisdictional electric utilities that have been granted authority to make wholesale sales at market-based rates. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS currently have wholesale market-based rate authorization from the FERC. The FERC adopted a new interim methodology to assess generation market power and modified measures to mitigate market power where it is found. The FERC upheld and clarified the interim requirements on rehearing in an order issued July 8, 2004. This methodology is to be applied to all initial market-based rate applications and triennial reviews. Under this methodology, the FERC has adopted two indicative screens (an uncommitted pivotal supplier analysis and an uncommitted market share analysis) to assess market power. Passage of the two screens creates a rebuttable presumption that an applicant does not have market power, while the failure creates a rebuttable presumption that the utility does have market power. An applicant or intervenor can rebut the presumption by performing a more extensive delivered-price test analysis. If an applicant is determined to have generation market power, the applicant has the opportunity to propose its own mitigation plan or may implement default mitigation established by the FERC. The default mitigation limits prices for sales of power to cost-based rates within areas where an applicant is found to have market power. Xcel Energy is reviewing the new interim requirements to determine what, if any, impact they will have on the wholesale market-based rate authority of the Xcel Energy 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 inter-tie transmission line between their systems to address the competitive impacts of that project. PSCo and SPS filed the required supplemental analysis on July 20, 2004. The FERC issued a notice of the filing of this supplemental analysis and no party filed comments. On Oct. 6, 2004, the FERC issued a notice of proposed rulemaking proposing to require electric utilities with market-based rates to file a “change in status report” regarding changes in transmission or generation ownership or operation that could affect eligibility for market-based rates. The change, if adopted, is not expected to go into effect in 2004.

Department of Energy Blackout Report – On April 6, 2004, the U.S. Department of Energy (DOE) issued its final report regarding the Aug. 14, 2003 electric blackout in the eastern United States, which did not affect the electric systems of the Xcel Energy regulated utilities. The report recommended 46 specific changes to current statutes, rules or practices in order to improve the reliability of the infrastructure used to transmit electric power. The recommendations included the establishment of mandatory reliability standards and financial penalties for noncompliance. On April 14, 2004, the FERC issued a policy statement requiring electric utilities, including the 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 utility subsidiaries submitted the required report on their vegetation management practices to the FERC in June 2004. Implementation of the blackout report recommendations and the FERC policy statement could increase future transmission costs, but the extent of this effect cannot be determined at this time.

Generation Interconnection Rules - On June 25, 2004, the FERC issued an order rejecting in part the April 2004 Xcel Energy compliance filing, regarding its utility subsidiaries, to FERC Order No. 2003-A, a FERC rule requiring all jurisdictional electric utilities to adopt uniform interconnection procedures and a standard form interconnection agreement for new generators of 20 megawatts or more. Xcel Energy had proposed very limited modifications to the pro forma procedure mandated by the FERC to facilitate compliance by PSCo with Colorado state least cost planning (LCP) rules, which require PSCo to analyze its loads and resource needs and select the least cost resource portfolio taking into account both generation and transmission costs. Xcel Energy argued the limited variations were necessary for PSCo to comply with both Order No. 2003-A and the Colorado LCP rules. The FERC

accepted the portions of the compliance filing adopting the pro forma process and agreement, but rejected the variations as contrary to Order No. 2003-A. On July 26, 2004, Xcel Energy requested rehearing of the FERC order and submitted a compliance filing to the June 25^th order. On Aug. 27, 2004, the FERC issued an order approving the compliance filing. On Sept. 27, 2004, Xcel Energy filed a request for rehearing in order to preserve the July 26^th request for rehearing. On Oct. 27, 2004, the FERC accepted the proposed tariff changes on rehearing, subject to certain conditions. The 2003 PSCo LCP proposal is pending before the CPUC and is expected to be supplemented to address the bid evaluation process.

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

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

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

Implementation of a wholesale regional market using the locational marginal cost pricing and financial transmission rights is expected to provide a benefit to NSP-Minnesota and NSP-Wisconsin through a reduction in overall wholesale power costs. However, Xcel Energy opposes certain aspects of the 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. Xcel Energy also cannot predict at this time whether the numerous remaining issues will be resolved in time to allow the Midwest ISO market to commence on March 1, 2005, as proposed.

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

Private Fuel Storage – NSP-Minnesota 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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

PSCo Capacity Cost Adjustment - In October 2003, PSCo filed an application to recover incremental capacity costs through a purchased capacity cost adjustment (PCCA) rider. The PCCA will recover purchased capacity payments to power suppliers that are not included in the determination of PSCo’s base electric rates determined in its 2002 general rate case or other recovery mechanisms. In May 2004, the CPUC granted the PSCo PCCA application, in part with new rates effective June 1, 2004. Primary provisions of the

initial CPUC ruling included a capped PCCA recovery for the period June 1, 2004 through Dec. 31, 2006 at PSCo’s current predicted capacity payments for a group of specific contracts, which will provide recovery of $20.4 million in 2004, $33.5 million in 2005 and $19.8 million in 2006. In addition, the CPUC excluded seven of the existing contracts from incremental recovery under the PCCA calculation. However, PSCo expects that the capacity costs from these contracts will be eligible for recovery through base rates when PSCo files its next general rate case. The energy costs from these contracts are eligible for recovery through the PSCo electric commodity adjustment clause.

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

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

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

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

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

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

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

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

California Refund Proceeding (PSCo) - A number of parties purchasing energy in markets operated by the California Independent System Operator (California ISO) or the California Power Exchange (PX) have asserted prices paid for such energy were unjust and unreasonable and that refunds should be made in connection with sales in those markets for the period Oct. 2, 2000 through June 20, 2001. PSCo supplied energy to these markets during this period and has been an active participant in the proceedings. The FERC ordered an investigation into the California ISO and PX spot markets and concluded that the electric market structure and market rules for wholesale sales of energy in California were flawed and have caused unjust and unreasonable rates for short-term energy under certain conditions. The FERC ordered modifications to the market structure and rules in California and established an ALJ to make findings with respect to, among other things, the amount of refunds owed by each supplier based on the difference between what was charged and what would have been charged in a more functional market, i.e., the “market clearing price,” which is based on the unit providing energy in an hour with the highest incremental cost. The initial proceeding related to California’s demand for $8.9 billion in refunds from power sellers. The ALJ subsequently stated that after assessing a refund of $1.8 billion for power prices, power suppliers were owed $1.2 billion because the state was holding funds owed to suppliers. Because of the low volume of sales that PSCo had into California after this date, PSCo’s exposure is estimated at approximately $3.4 million, which is offset by amounts owed by the California ISO to PSCo in excess of that amount.

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

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

PSCo and SPS FERC Transmission Rate Case - On Sept. 2, 2004, and as amended on Oct. 13, 2004, Xcel Energy filed on behalf of PSCo and SPS an application to increase wholesale transmission service and ancillary service rates within the Xcel Energy joint open access transmission tariff. PSCo and SPS are seeking an increase in annual transmission service and ancillary services revenues of

$6.1 million. As a result of a settlement with certain PSCo wholesale power customers in 2003, power rates would be reduced by $1.4 million. The net increase in annual revenues proposed is $4.7 million, effective Dec. 13, 2004. The rate increase application also includes PSCo and SPS adopting an annual formula rate for transmission service pricing as previously approved by the FERC for other transmission providers. The filing is pending FERC review.

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

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

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

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

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

6. Commitments and Contingent Liabilities

Environmental Contingencies

Xcel Energy and its subsidiaries are subject to regulations covering air and water quality, land use, the storage of natural gas and the storage and disposal of hazardous or toxic wastes. Compliance is continually assessed. Regulations, interpretations and enforcement policies can change, which may impact the cost of building and operating facilities. 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.

Federal Clean Water Act – The Federal Clean Water Act addresses the environmental impacts of cooling water intakes. In July 2004, the Environmental Protection Agency (EPA) published phase II of the rule that applies to existing cooling water intakes at steam-electric power plants. The rule will require 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 capital costs to Xcel Energy are estimated at approximately $55 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.

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

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

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

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

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

Legal Contingencies

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

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.

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

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

On July 9, 2004, the federal Court of Appeals for the District of Columbia issued its decision in consolidated cases challenging regulations and decisions on the federal nuclear waste program. The Court of Appeals rejected challenges by the state of Nevada and other intervenors with respect to the majority of the licensing regulations of the NRC, the congressional resolution selecting Yucca Mountain as the site of the permanent repository, and the DOE and presidential actions leading to the selection of Yucca Mountain. The Court of Appeals vacated the 10,000 year compliance period adopted by EPA regulations governing spent nuclear fuel disposal and incorporated in the NRC regulations governing Yucca Mountain licensing. 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 district 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 compensation received, and awards of fees and expenses. In each of the cases, the defendants filed motions to dismiss the complaint or amended complaint for failure to make a proper pre-suit demand, or in the federal court case, to make any pre-suit demand at all, upon Xcel Energy’s board of directors. In January 2004, the state district court judge granted the defendants’ motion to dismiss both of the state court actions. In March 2004, plaintiffs filed notices of appeal related to this decision. In April 2004, plaintiffs withdrew their appeals. On July 12, 2004, the federal district court issued an order granting the defendants’ motion to dismiss the federal derivative lawsuit. Plaintiffs in the federal derivative lawsuit have appealed the federal court’s dismissal.

SchlumbergerSema, Inc. vs. Xcel Energy Inc. (NSP-Minnesota) - Under a 1996 data services agreement, SchlumbergerSema, Inc. (SLB) provides automated meter reading, distribution automation, and other data services to NSP-Minnesota. In September 2002, NSP-Minnesota issued written notice that SLB committed events of default under the agreement, including SLB’s nonpayment of approximately $7.4 million for distribution automation assets. In November 2002, SLB demanded arbitration and asserted various claims against NSP-Minnesota totaling approximately $24 million for alleged breach of an expansion contract and a meter purchasing contract. In the arbitration, NSP-Minnesota asserted counterclaims against SLB including those related to SLB’s failure to meet performance criteria, improper billing, failure to pay for use of NSP-Minnesota owned property and failure to pay $7.4 million for NSP-Minnesota distribution automation assets, for total claims of approximately $41 million. NSP-Minnesota also sought a declaratory judgment from the arbitrators that would terminate SLB’s rights under the data services agreement. In August 2004, the

U.S. Bankruptcy Court for the District of Delaware ruled that claims related to use of certain equipment are barred unless NSP-Minnesota can establish a basis for the claims in SLB’s conduct subsequent to the time of the assumption of this contract by SLB. Unless NSP-Minnesota can establish that basis, the decision would reduce NSP-Minnesota’s damage claim by approximately $5.5 million.

Cornerstone Propane Partners, L.P., et al., vs. e prime, inc., et al. — In February 2004, a purported class action complaint was filed in the U.S. District Court for the Southern District of New York against e prime and three other defendants, by Cornerstone Propane Partners, L.P., Robert Calle Gracey and Dominick Viola on behalf of a class who purchased or sold one or more New York Mercantile Exchange natural gas futures and/or options contracts during the period from Jan. 1, 2000 to Dec. 31, 2002. The complaint alleges that defendants manipulated the price of natural gas futures and options and/or the price of natural gas underlying those contracts in violation of the Commodities Exchange Act. In February 2004, the plaintiff requested that this action be consolidated with a similar suit involving Reliant Energy Services. In February 2004, defendants, including e prime, filed motions to dismiss. In September 2004, the U.S. District Court denied the motions to dismiss.

Fairhaven Power Company vs. Encana Corporation, et al. — On Sept. 14, 2004, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Fairhaven Power Co. and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inflate prices. Xcel Energy has not responded to the complaint. The case is in the early stages, there has been no discovery, and Xcel Energy intends to vigorously defend against these claims.

Department of Labor Audit — In 2001, Xcel Energy received notice from the Department of Labor (DOL) Employee Benefit Security Administration that it intended to audit the Xcel Energy pension plan. After multiple on-site meetings and interviews with Xcel Energy personnel, the DOL indicated on May 18, 2004, that it is prepared to take the position that Xcel Energy, as plan sponsor and through its delegate, the Pension Trust Administration Committee, breached its fiduciary duties under ERISA with respect to certain investments made in limited partnerships and hedge funds in 1997 and 1998. The DOL has offered to conclude the audit at this time if Xcel Energy is willing to contribute to the plan the full amount of losses from the questioned investments, or approximately $7 million. Xcel Energy formally responded on July 19, 2004 with a letter to the DOL that asserted no fiduciary violations have occurred, and extended an offer to meet to discuss the matter further. If the DOL offer is put into effect, the requested contribution would affect cash flows only and not the net income of Xcel Energy.

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

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

Lamb County Electric Cooperative (SPS) - On July 24, 1995, Lamb County Electric Cooperative, Inc. (LCEC) petitioned the PUCT for a cease and desist order against SPS alleging that SPS was unlawfully providing service to oil field customers in LCEC’s certificated area. On May 23, 2003, the PUCT issued an order denying LCEC’s petition based on its determination that SPS was granted a certificate in 1976 to serve the disputed customers. LCEC appealed the decision to the District Court in Travis County, Texas and on Aug. 12, 2004, the District Court affirmed the decision of the PUCT. On Sept. 9, 2004, LCEC appealed the District

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 Sept. 30,
(Millions of Dollars)	2004			2003
Accumulated other comprehensive income (loss) related to cash flow hedges at June 30	$	18.1		$	(38.5	)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges	(11.2		)	60.4
After-tax net realized gains on derivative transactions reclassified into earnings	(4.6		)	(12.6		)
Accumulated other comprehensive income related to cash flow hedges at Sept. 30	$	2.3		$	9.3

	Nine months ended Sept. 30,
(Millions of Dollars)	2004			2003
Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	8.1		$	22.1
After-tax net unrealized gains related to derivatives accounted for as hedges	2.6			87.9
After-tax net realized gains on derivative transactions reclassified into earnings	(8.4		)	(100.7		)
Accumulated other comprehensive income related to cash flow hedges at Sept. 30	$	2.3		$	9.3

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.

Cash Flow Hedges

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

At Sept. 30, 2004, Xcel Energy and its utility subsidiaries had various commodity-related contracts designated as cash flow hedges extending through 2009. The fair value of these cash flow hedges is recorded in either Other Comprehensive Income or deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place. Amounts deferred in these accounts are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the physical purchase or sale of electric energy, the use of natural gas to generate electric energy or natural gas purchased for resale. As of Sept. 30, 2004, Xcel Energy had no amounts accumulated in Other Comprehensive Income related to commodity cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle. However, due to the volatility of commodities markets, the value in Other Comprehensive Income will likely change prior to its recognition in earnings.

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 gains from Other Comprehensive Income related to interest rate cash flow hedge contracts of approximately $0.2 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 natural gas purchased for resale are recorded as a component of natural gas costs and interest rate hedging transactions are recorded as a component of interest expense. Certain Xcel Energy utility subsidiaries are allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. There was no hedge ineffectiveness in the third 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 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 that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that meet the requirements of normal are documented and exempted from the fair value accounting and reporting requirements of SFAS No. 133.

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.

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

9. Detail of Interest and Other Income – Net of Other Expense

Interest and other income (expense), net is comprised of the following:

	Three months ended Sept. 30,						Nine months ended Sept. 30,
(Thousands of Dollars)	2004			2003			2004			2003
Allowance for equity funds used during construction	$	7,400		$	6,058		$	24,084		$	18,140
Interest income	2,261			3,219			8,357			13,022
Equity income (loss) in unconsolidated affiliates	468			3,179			1,412			(1,088		)
Gain on sale of water rights at Utility Engineering	—			15,055			—			15,055
Other income	3,270			(798		)	6,842			1,718
Minority interest expense	(196		)	—			(203		)	—
Interest expense on corporate-owned life insurance and other	(5,856		)	(6,090		)	(18,293		)	(16,983		)
Total interest and other income, net of other expenses	$	7,347		$	20,623		$	22,199		$	29,864

10. Common Stock and Equivalents

Xcel Energy has common stock equivalents consisting of convertible senior notes and options. The dilutive impacts of common stock equivalents affected earnings per share as follows for the three and nine months ended Sept. 30, 2004 and 2003:

	Three months ended Sept. 30, 2004							Three months ended Sept. 30, 2003
(Amounts in thousands, except per share amounts)	Income			Shares	Per share Amount			Income				Shares	Per share Amount
Income from continuing operations	$	166,183						$		184,648
Less: Dividend requirements on preferred stock	(1,060		)					(1,060			)
Basic earnings per share:
Income from continuing operations	165,123			399,746	$	0.41		183,588				398,751	$	0.46
Effect of dilutive securities:
$230 million convertible debt	3,046			18,654				2,803				18,654
$57.5 million convertible debt	761			4,663				—				—
Convertible debt option	—			—				—				706
Options	—			15				—				17
Diluted earnings per share:
Income from continuing operations and assumed conversions	$	168,930		423,078	$		0.40	$	186,391			418,128	$		0.44

	Nine months ended Sept. 30, 2004								Nine months ended Sept. 30, 2003
(Amounts in thousands, except per share amounts)	Income				Shares	Per share Amount			Income				Shares	Per share Amount
Income from continuing operations	$	400,340							$	372,910
Less: Dividend requirements on preferred stock	(3,180			)					(3,180			)
Basic earnings per share:
Income from continuing operations	397,160				399,184	$	0.99		369,730				398,728	$	0.93
Effect of dilutive securities:
$230 million convertible debt	8,895				18,654				8,409				18,654
$57.5 million convertible debt	2,224				4,663				—				—
Convertible debt option	—				—				—				405
Options	—				16				—				11
Diluted earnings per share:
Income from continuing operations and assumed conversions	$		408,279		422,517	$		0.97	$		378,139		417,798	$		0.91

11. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three months ended Sept. 30,
	2004			2003				2004				2003
(Thousands of Dollars) Xcel Energy Inc.	Pension Benefits							Postretirement Health Care Benefits
Service cost	$	14,143		$		16,867		$	1,525			$	1,475
Interest cost	41,349			42,688				13,151				13,107
Expected return on plan assets	(75,690		)	(80,514			)	(5,812			)	(5,547			)
Amortization of transition (asset) obligation	(2		)	(499			)	3,644				3,857
Amortization of prior service cost (credit)	7,503			7,062				(544			)	(384			)
Amortization of net (gain) loss	(3,688		)	(11,210			)	5,412				3,853
Net periodic benefit cost (credit)	(16,385		)	(25,606			)	17,376				16,361
Settlements and curtailments	(223		)	—				—				—
Costs not recognized due to the effects of regulation	10,480			12,938				—				—
Additional cost recognized due to the effects of regulation	—			—				973				973
Net benefit cost (credit) recognized for financial reporting	$	(6,128	)	$	(12,668		)	$		18,349		$		17,334

	Nine months ended Sept. 30,
	2004				2003				2004				2003
(Thousands of Dollars) Xcel Energy Inc.	Pension Benefits								Postretirement Health Care Benefits
Service cost	$		43,617		$	50,601			$	4,575			$	4,420
Interest cost	124,023				128,064				39,453				39,320
Expected return on plan assets	(227,222			)	(241,542			)	(17,438			)	(16,639			)
Amortization of transition (asset) obligation	(6			)	(1,497			)	10,934				11,570
Amortization of prior service cost (credit)	22,509				21,186				(1,634			)	(1,150			)
Amortization of net (gain) loss	(11,406			)	(33,630			)	16,238				11,558
Net periodic benefit cost (credit)	(48,485			)	(76,818			)	52,128				49,079
Settlements and curtailments	(926			)	1,309				—				(2,128			)
Costs not recognized due to the effects of regulation	29,225				38,483				—				—
Additional cost recognized due to the effects of regulation	—				—				2,918				2,911
Net benefit cost (credit) recognized for financial reporting	$	(20,186		)	$		(37,026	)	$		55,046		$		49,862

Employer Contributions

In August 2004, Xcel Energy’s subsidiaries, PSCo and CLF&P, contributed approximately $9 million and $1 million, respectively, to their bargaining pension plans. Xcel Energy anticipates contributing $55 million during 2004 to fund its retiree medical and life insurance plans, of which $27 million has been contributed at Sept. 30, 2004.

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.

(Thousands of Dollars)	Regulated Electric Utility				Regulated Natural Gas Utility				All Other				Reconciling Eliminations				Consolidated Total
Three months ended Sept. 30, 2004
Operating revenues from external customers	$	1,784,270			$	191,096			$	33,246			$		—		$	2,008,612
Intersegment revenues	304				1,120				9,209				(10,633			)	—
Total revenues	$	1,784,574			$	192,216			$		42,455		$		(10,633	)	$		2,008,612
Income (loss) from continuing operations	$	170,115			$	(5,821		)	$			12,029	$	(10,140		)	$		166,183
Three months ended Sept. 30, 2003
Operating revenues from external customers	$	1,765,351			$	178,731			$		57,518		$	—			$			2,001,600
Intersegment revenues	269				6,359				11,204				(17,832			)	—
Total revenues	$		1,765,620		$		185,090		$			68,722	$	(17,832		)	$			2,001,600
Income (loss) from continuing operations	$			201,244	$		(6,790	)	$			2,143	$	(11,949		)	$			184,648

(Thousands of Dollars)	Regulated Electric Utility		Regulated Natural Gas Utility				All Other			Reconciling Eliminations				Consolidated Total
Nine months ended Sept. 30, 2004
Operating revenues from external customers	$	4,735,046	$	1,227,269			$	123,583		$	—			$	6,085,898
Intersegment revenues	848		6,781				27,485			(35,114			)	—
Total revenues	$	4,735,894	$		1,234,050		$	151,068		$	(35,114		)	$	6,085,898
Income (loss) from continuing operations	$	358,984	$			40,227	$	26,404		$	(25,275		)	$	400,340
Nine months ended Sept. 30, 2003
Operating revenues from external customers	$	4,509,670	$			1,099,744	$	163,420		$	—			$	5,772,834
Intersegment revenues	830		9,907				34,451			(45,188			)	—
Total revenues	$	4,510,500	$	1,109,651			$		197,871	$		(45,188	)	$	5,772,834
Income (loss) from continuing operations	$	356,606	$	52,275			$		954	$	(36,925		)	$		372,910

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

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

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “estimate,” “expect,” “objective,” “outlook,” “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 natural gas pipeline constraints;

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

• Increased competition in the utility industry or additional competition in the markets served by 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 Sept. 30, 2004.

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:

• Seren, a nonregulated subsidiary, which was classified as held for sale in the third quarter of 2004 based on a decision to divest it;

• 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 Sept. 30,
Contribution to Earnings (Millions of Dollars)	2004			2003

GAAP income (loss) by segment
Regulated electric utility segment income — continuing operations	$	170.1		$	201.2
Regulated natural gas utility segment loss — continuing operations	(5.8		)	(6.8		)
Other utility results (a)	9.2			(5.8		)
Total utility segment income — continuing operations	173.5			188.6
Other nonregulated results and holding company costs (a)	(7.3		)	(4.0		)
Total income — continuing operations	166.2			184.6
Regulated utility income — discontinued operations	0.4			0.4
Other nonregulated income (loss) — discontinued operations	(119.9		)	102.4
Total income (loss) — discontinued operations	(119.5		)	102.8
Total GAAP income	$	46.7		$	287.4

	Nine months ended Sept. 30,
Contribution to Earnings (Millions of Dollars)	2004			2003

GAAP income (loss) by segment
Regulated electric utility segment income — continuing operations	$	359.0		$	356.6
Regulated natural gas utility segment income — continuing operations	40.2			52.3
Other utility results (a)	20.9			1.8
Total utility segment income — continuing operations	420.1			410.7
Other nonregulated results and holding company costs (a)	(19.8		)	(37.8		)
Total income — continuing operations	400.3			372.9
Regulated utility income — discontinued operations	1.9			23.7
NRG loss — discontinued operations	—			(362.2		)
Other nonregulated income (loss) — discontinued operations	(119.3		)	110.5
Total loss — discontinued operations	(117.4		)	(228.0		)
Total GAAP income	$	282.9		$	144.9

	Three months ended Sept. 30,
	2004			2003
GAAP earnings per share contribution by segment
Regulated electric utility segment — continuing operations	$	0.40		$	0.48
Regulated natural gas utility segment — continuing operations	(0.01		)	(0.02		)
Other utility results (a)	0.02			(0.01		)
Total utility segment earnings per share — continuing operations	0.41			0.45
Financing costs and preferred dividends — holding company	(0.02		)	(0.02		)
Other nonregulated results and holding company costs (a)	0.01			0.01
Total earnings per share — continuing operations	0.40			0.44
Other nonregulated earnings (loss) — discontinued operations	(0.28		)	0.25
Total earnings (loss) per share — discontinued operations	(0.28		)	0.25
Total GAAP earnings per share — diluted	$	0.12		$	0.69

	Nine months ended Sept. 30,
	2004			2003
GAAP earnings per share contribution by segment
Regulated electric utility segment — continuing operations	$	0.85		$	0.85
Regulated natural gas utility segment — continuing operations	0.09			0.13
Other utility results (a)	0.05			——
Total utility segment earnings per share — continuing operations	0.99			0.98
Financing costs and preferred dividends — holding company	(0.06		)	(0.07		)
Other nonregulated results and holding company costs (a)	0.04			——
Total earnings per share — continuing operations	0.97			0.91
Regulated utility earnings — discontinued operations	—			0.06
NRG loss — discontinued operations	—			(0.87		)
Other nonregulated earnings (loss) — discontinued operations	(0.28		)	0.26
Total loss per share — discontinued operations	(0.28		)	(0.55		)
Total GAAP earnings per share — diluted	$	0.69		$	0.36

(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 policies for PSCo employees and retirees.

The following table summarizes significant components contributing to the changes in the three months and nine months ended Sept. 30, 2004 earnings per share compared with the same periods in 2003, which are discussed in more detail later.

	Three months ended Sept. 30, 2004 vs. 2003			Nine months ended Sept. 30, 2004 vs. 2003
Change in Earnings Per Share – Continuing Operations
Unfavorable weather	$	(0.07	)	$	(0.09	)
Lower depreciation and amortization expense	0.01			0.08
Higher short-term electric wholesale and trading margins	—			0.05
Lower (higher) utility operating and maintenance expense	0.01			(0.04		)
Lower financing costs	—			0.03
Other	0.01			0.03
Net change in earnings per share – continuing operations	(0.04		)	0.06
Changes in Earnings Per Share – Discontinued Operations	(0.53		)	0.27
Total increase (decrease) in earnings per share - diluted	$	(0.57	)	$	0.33

Utility Segment Results

For the third quarter of 2004, net income from utility operations decreased largely due to adverse weather impacts which was partially offset by lower depreciation expense and lower utility operating and maintenance expenses.

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):

	Earnings Per Share Increase (Decrease)
	2004 vs. Normal			2003 vs. Normal		2004 vs. 2003
Three months ended Sept. 30	$	(0.04	)	$	0.03	$	(0.07	)
Nine months ended Sept. 30	$	(0.07	)	$	0.02	$	(0.09	)

Other Results — Nonregulated Subsidiaries and Holding Company Costs

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

	Three months ended Sept. 30,						Nine months ended Sept. 30,
	2004			2003			2004			2003
Financing costs and preferred dividends – holding company	$	(0.02	)	$	(0.02	)	$	(0.06	)	$	(0.07	)
Other nonregulated results and holding company	0.01			0.01			0.04			—
Total other nonregulated and holding company	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	(0.07	)

Financing Costs and Preferred Dividends – Nonregulated and holding company results include interest expense and preferred dividend costs, which are incurred at the Xcel Energy and intermediate holding company levels and are not directly assigned to individual subsidiaries.

Other Nonregulated Results – Other nonregulated results and holding company earnings improved for the nine months ended Sept. 30, 2004, compared with the same period in 2003, due to restructuring charges related to NRG, which were recorded in the second quarter of 2003 and did not recur in 2004. The restructuring charges were incurred by Xcel Energy and are not considered discontinued operations. Reduced losses at Planergy International Inc., whose operations were closed or sold in 2003 and early 2004 also contributed to the improvement. In addition, certain one-time tax benefits were recorded in the second quarter of 2004.

Discontinued Operations

	Three months ended Sept. 30,					Nine months ended Sept. 30,
	2004			2003		2004			2003
Utility segments	$	—		$	—	$	—		$	0.06
NRG segment	—			—		—			(0.87		)
All other segment	(0.28		)	0.25		(0.28		)	0.26
Total discontinued operations	$	(0.28	)	$	0.25	$	(0.28	)	$	(0.55	)

Discontinued Nonregulated Operations – All Other Segment

Seren Innovations, Inc. – On Sept. 27, 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Xcel Energy’s broadband communications services operated through Seren. Seren delivers cable television, high-speed Internet and telephone service over an advanced network to approximately 45,000 customers in St. Cloud, Minn., and Concord and Walnut Creek, Calif.

Xcel Energy International, Inc. and e prime, Inc. – 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’s operations primarily included 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 exit of all business conducted by e prime was completed in 2004. Also during

2004, Xcel Energy completed the sale of Argentina subsidiaries of Xcel Energy International. For sales in the first three quarters of 2004, the total sales price was estimated at approximately $23 million, including certain adjustments subject to finalization. Approximately $15 million of the sales price has been placed in escrow, which is expected to remain in place until the first quarter of 2005, to support Xcel Energy’s customary indemnity obligations under the sales agreement. In addition to the sales price, Xcel Energy also received approximately $21 million at closing as a redemption of its capital investment. The sale resulted in an after-tax gain of $3.8 million through the third quarter of 2004. The gain includes the realization of $6.5 million of tax benefits related to the now-realizable tax loss from disposition of Xcel Energy International assets. Xcel Energy International is in the process of closing its remaining assets and operations and expects to exit the businesses held for sale during 2004.

On Oct. 25, 2004, Xcel Energy closed on the sale of the stock of Electrica del Sur S.A. and Energia del Sur S.A. to Patagonia Energy Ltd. Its primary asset is a 76 megawatt gas-fired facility in Argentina. The sale is expected to result in a pretax gain of approximately $2.5 million in the fourth quarter of 2004. Xcel Energy International is in the process of closing its remaining assets and operations and expects to exit the businesses held for sale during 2004.

Tax Benefits Related to Investment in NRG - With NRG’s emergence from bankruptcy in December 2003, Xcel Energy divested its ownership interest in NRG and reported a loss deduction in its 2003 tax return. These tax benefits, related to Xcel Energy’s investment in discontinued NRG operations, are also reported as discontinued operations. In late August 2003, Xcel Energy determined that the tax basis in NRG was greater than originally estimated and that additional state tax benefits were available related to its investment in NRG. Based on revised estimates, Xcel Energy recorded $105 million, or 25 cents per share, of additional tax benefits in the third quarter of 2003.

Discontinued Utility 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 is reporting CLF&P results as a component of discontinued operations for all periods presented. The sale is pending SEC approval under the Public Utility Holding Company Act and is expected to be completed in 2004.

During 2003, Xcel Energy completed the sale of two subsidiaries in its regulated natural gas utility segment, BMG and Viking, including 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.

Discontinued Nonregulated Operations - NRG – Xcel Energy’s share of NRG’s results for 2003 and prior periods are reported as a component of discontinued operations due to NRG’s emergence from bankruptcy in December 2003 and 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.

Income Statement Analysis — Third Quarter 2004 vs. Third 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.

(Millions of Dollars)	Base Electric Utility			Short- Term Wholesale			Electric Commodity Trading			Consolidated Total
Three months ended Sept. 30, 2004
Electric utility revenue	$	1,700		$	76		$	—		$	1,776
Electric fuel and purchased power	(833		)	(56		)	—			(889		)
Electric trading revenue - gross	—			—			256			256
Electric trading costs	—			—			(248		)	(248		)
Gross margin before operating expenses	$	867		$	20		$	8		$	895
Margin as a percentage of revenue	51.0		%	26.3		%	3.1		%	44.0		%

Three months ended Sept. 30, 2003
Electric utility revenue	$	1,712		$	43		$	—		$	1,755
Electric fuel and purchased power	(787		)	(27		)	—			(814		)
Electric trading revenue - gross	—			—			124			124
Electric trading costs	—			—			(113		)	(113		)
Gross margin before operating expenses	$	925		$	16		$	11		$	952
Margin as a percentage of revenue	54.0		%	37.2		%	8.9		%	50.7		%

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

Base Electric Utility Revenue

(Millions of Dollars)	2004 vs. 2003
Estimated impact of weather	$	(64	)
Fuel, purchased power and capacity cost recovery	40
Firm wholesale	18
Quality of service obligations	5
Capacity sales	(4		)
Sales growth (excluding weather impact)	1
Other	(8		)
Total base electric utility revenue decrease	$	(12	)

Base Electric Utility Margin

(Millions of Dollars)	2004 vs. 2003
Estimated impact of weather	$	(50	)
Purchased capacity and other costs	(13		)
Quality of service obligations	5
Capacity sales	(4		)
Regulatory adjustments	(2		)
Other	6
Total base electric utility margin decrease	$	(58	)

Short-term wholesale and electric commodity trading margins increased approximately $1 million during the third quarter of 2004 compared with the third quarter of 2003.

Natural Gas Utility Margins

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.

	Three Months Ended Sept. 30,
(Millions of Dollars)	2004			2003
Natural gas utility revenue	$	191		$	179
Cost of natural gas sold and transported	(111		)	(101		)
Natural gas utility margin	$	80		$	78

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

Natural Gas Revenue

(Millions of Dollars)	2004 vs. 2003
Purchased natural gas adjustment clause recovery	$	11
Sales growth (excluding weather impact)	2
Estimated impact of weather on firm sales volumes	(1		)
Base rate changes – Colorado	(1		)
Transportation and other	1
Total natural gas revenue increase	$	12

Natural Gas Margin

(Millions of Dollars)	2004 vs. 2003
Sales growth (excluding weather impact)	$	2
Estimated impact of weather on firm sales volumes	(1		)
Base rate changes – Colorado	(1		)
Transportation and other	2
Total natural gas margin increase	$	2

Nonregulated Operating Margins

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

	Three Months Ended Sept. 30,
(Millions of Dollars)	2004			2003
Nonregulated and other revenue	$	33		$	58
Cost of sales – nonregulated and other	(15		)	(46		)
Nonregulated margin	$	18		$	12

Non-Fuel Operating Expense and Other Costs

Utility Other Operation and Maintenance Expenses for the third quarter of 2004 decreased by approximately $4 million, or 1.1 percent, compared with the same period in 2003.

Depreciation and amortization expense decreased by approximately $10 million, or 5.4 percent, for the third quarter of 2004, when compared with the third quarter of 2003. During 2003, the Minnesota legislature authorized additional spent nuclear fuel storage at the Prairie Island nuclear plant. In December 2003, the MPUC extended the authorized useful lives of the two generating units at the Prairie Island nuclear plant retroactive to Jan. 1, 2003. The 2003 annual reduction was recorded in the fourth quarter of 2003.

Interest charges and financing costs decreased $2 million, or 1.8 percent, for the third 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 $6 million and $5 million in the third quarter of 2004 and 2003, respectively, for interest capitalized.

Income taxes decreased by $21 million during the third quarter of 2004 compared with the same period in 2003. The decrease was primarily due to decreased pretax income in 2004. The effective tax rate for continuing operations was 30.9 percent for the third quarter of 2004, compared with 34.0 percent for the same period in 2003. The effective tax rate for the third quarter of 2004 is higher than the forecasted 2004 annual tax rate due mainly to a higher proportion of the annual income earned in the third quarter from entities with effective tax rates higher than the consolidated effective tax rate.

Income Statement Analysis — First Nine Months of 2004 vs. First Nine 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.

(Millions of Dollars)	Base Electric Utility			Short- Term Wholesale			Electric Commodity Trading			Consolidated Total
Nine months ended Sept. 30, 2004
Electric utility revenue	$	4,529		$	193		$	—		$	4,722
Electric fuel and purchased power	(2,182		)	(109		)	—			(2,291		)
Electric trading revenue-gross	—			—			493			493
Electric trading costs	—			—			(479		)	(479		)
Gross margin before operating expenses	$	2,347		$	84		$	14		$	2,445
Margin as a percentage of revenue	51.8		%	43.5		%	2.8		%	46.9		%

Nine months ended Sept. 30, 2003
Electric utility revenue	$	4,350		$	144		$	—		$	4,494
Electric fuel and purchased power	(1,947		)	(99		)	—			(2,046		)
Electric trading revenue-gross	—			—			256			256
Electric trading costs	—			—			(241		)	(241		)
Gross margin before operating expenses	$	2,403		$	45		$	15		$	2,463
Margin as a percentage of revenue	55.2		%	31.3		%	5.9		%	51.9		%

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

Base Electric Utility Revenue

(Millions of Dollars)	2004 vs. 2003
Fuel, purchased power and capacity cost recovery	$	187
Estimated impact of weather	(69		)
Sales growth (excluding weather impact)	45
Firm wholesale	27
Renewable development fund (offset by decrease in depreciation expense)	(6		)
Quality of service obligations	(5		)
Total base electric utility revenue increase	$	179

Base Electric Utility Margin

(Millions of Dollars)	2004 vs. 2003
Estimated impact of weather	$	(53	)
Sales growth (excluding weather impact)	34
Purchased capacity and other costs	(18		)
Regulatory adjustments	(8		)
Renewable development fund (offset by decrease in depreciation expense)	(6		)
Quality of service obligations	(5		)
Other	—
Total base electric utility margin decrease	$	(56	)

Short-term wholesale margins increased $39 million for the first nine months of 2004 compared with the same period in 2003. The higher results reflect a number of market factors, including higher market prices, additional resources available for sale and a pre-existing contract, which expired in the first quarter of 2004.

Natural Gas Utility Margins

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2004			2003
Natural gas utility revenue	$	1,227		$	1,100
Cost of natural gas sold and transported	(892		)	(746		)
Natural gas utility margin	$	335		$	354

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

Natural Gas Revenue

(Millions of Dollars)	2004 vs. 2003
Sales growth (excluding weather impact)	$	(2	)
Estimated impact of weather on firm sales volume	(8		)
Purchased natural gas adjustment clause recovery	150
Base rate changes – Colorado	(15		)
Transportation and other	2
Total natural gas revenue increase	$	127

Natural Gas Margin

(Millions of Dollars)	2004 vs. 2003
Sales growth (excluding weather impact)	$	1
Estimated impact of weather on firm sales volume	(5		)
Base rate changes – Colorado	(15		)
Transportation and other	—
Total natural gas margin decrease	$	(19	)

Nonregulated Operating Margins

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

	Nine Months EndedSept. 30,
(Millions of Dollars)	2004			2003
Nonregulated and other revenue	$	124		$	163
Cost of sales – nonregulated and other	(66		)	(109		)
Nonregulated margin	$	58		$	54

Non-Fuel Operating Expense and Other Costs

Utility Other Operation and Maintenance Expenses for the first nine months of 2004 increased by approximately $26 million, or 2.3 percent, compared with the same period in 2003. The increase is primarily due to lower pension credits of $18 million, higher bad debt reserves of $8 million, costs for services provided to others where reimbursements are recorded in revenue of $8 million, higher medical and health insurance costs of $5 million and higher reliability costs of $5 million. The higher costs were partially offset by lower plant outage costs of $14 million and lower restricted stock expense related to the 2003 grant of $5 million.

Depreciation and amortization expense decreased by approximately $52 million, or 9.1 percent, for the first nine months of 2004, when compared with the same period in 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 from NSP-Minnesota customers in rates,

• 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, which decreased depreciation expense by $22 million. In addition, annual depreciation expense for 2004 is expected to be approximately $18 million lower than 2003, due to a change in the decommissioning accruals resulting from a related 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. PSCo will experience the full impact of the annual reduction in 2004, resulting in a decrease in depreciation expense of $10 million for 2004 compared with 2003.

Interest charges and financing costs decreased $23 million, or 6.7 percent, for the nine month period ended Sept. 30, 2004, compared with the same period in 2003. The decrease reflects savings from refinancing higher coupon debt during 2003. Interest expense was reduced by $17 million and $15 million in the year to date periods ended Sept. 30, 2004 and Sept. 30, 2003, respectively, for interest capitalized.

Income taxes decreased for the nine months ended Sept. 30, 2004, compared with Sept. 30, 2003, by $1 million. The decrease was primarily due to a lower effective tax rate for 2004. The effective tax rate for continuing operations was 28.8 percent for the period ended Sept. 30, 2004, compared with 30.4 percent for the same period in 2003. The decreased rate in 2004 is due mainly to a larger ratio of tax credits and allowance for funds used during construction related to equity financing to lower pretax income levels.

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 Sept. 30, 2004, there were no material changes to the financial market risks that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2003, 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 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. The VaR is calculated using a three day holding period for both electricity and natural gas. Previously, Xcel Energy calculated VaR using a holding period of five days for electricity and two days for natural gas. However, the methodology was changed to ensure consistency in risk measurement across both commodities. Xcel Energy’s revised holding periods remain consistent with current industry practice. VaR using the previous and current methodology for the three months ended Sept. 30, 2004, is as follows:

Current Methodology	Period Ended Sept. 30, 2004		Change from Period Ended June 30, 2004		VaR Limit		Average		High		Low
(Millions of Dollars)
Electric Commodity Trading (1)	$	1.29	$	0.35	$	5.0	$	1.03	$	1.72	$	0.41

Previous Methodology	Period Ended Sept. 30, 2004		Change from Period Ended June 30, 2004		VaR Limit		Average		High		Low
(Millions of Dollars)
Electric Commodity Trading (1)	$	1.66	$	0.45	$	6.0	$	1.34	$	2.22	$	0.53

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

Energy Trading and Hedging Activities

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 transportation contracts and other physical and financial contracts.

For the period ended Sept. 30, 2004, these contracts, with the exception of transmission and natural gas transportation contracts and contracts qualifying for a normal purchase or normal sale scope exception, which meet the definition of a derivative in accordance with SFAS No. 133, were marked to market. Changes in fair value of energy trading contracts that do not qualify for hedge accounting treatment are recorded in income in the reporting period in which they occur.

The changes to the fair value of the energy trading contracts for the nine months ended Sept. 30, 2004 and 2003 were as follows:

	Nine months ended Sept. 30,
(Millions of Dollars)	2004			2003
Fair value of contracts outstanding at Jan. 1	$	4.2		$	(0.1	)
Contracts realized or otherwise settled during the period	(18.4		)	(5.5		)
Fair value of trading contract additions and changes during the period	14.9			16.1
Fair value of contracts outstanding at Sept. 30	$	0.7		$	10.5

As of Sept. 30, 2004, the sources of fair value of the energy trading and hedging net assets are as follows:

Trading Contracts

	Futures/Forwards
(Thousands of Dollars)	Source of Fair Value	Maturity Less Than 1 Year			Maturity 1 to 3 Years			Maturity 4 to 5 Years	Maturity Greater Than 5 Years	Total Futures/ Forwards Fair Value
NSP-Minnesota	(1)	$	(750	)	$	(330	)	—	—	$	(1,080	)
	(2)	2,027			295			—	—	2,322
PSCo	(1)	466			—			—	—	466
	(2)	(706		)	(115		)	—	—	(821		)
Total Futures/Forwards Fair Value		$	1,037		$	(150	)	—	—	$	887

	Options
(Thousands of Dollars)	Source of Fair Value	Maturity Less Than 1 Year			Maturity 1 to 3 Years	Maturity 4 to 5 Years	Maturity Greater Than 5 Years	Total Options Fair Value
NSP-Minnesota	(2)	$	2		—	—	—	$	2
PSCo	(2)	(189		)	—	—	—	(189		)
Total Options Fair Value		$	(187	)	—	—	—	$	(187	)

Hedge Contracts

	Futures/Forwards
(Thousands of Dollars)	Source of Fair Value	Maturity Less Than 1 Year		Maturity 1 to 3 Years	Maturity 4 to 5 Years	Maturity Greater Than 5 Years	Total Futures/ Forwards Fair Value
PSCo	(2)	$	823	—	—	—	$	823
Total Futures/Forwards Fair Value		$	823	—	—	—	$	823

	Options
(Thousands of Dollars)	Source of Fair Value	Maturity Less Than 1 Year		Maturity 1 to 3 Years		Maturity 4 to 5 Years	Maturity Greater Than 5 Years	Total Options Fair Value
NSP-Minnesota	(2)	$	5,848	—		—	—	$	5,848
NSP-Wisconsin	(2)	1,296		—		—	—	1,296
PSCo	(2)	18,469		1,060		—	—	19,529
Total Options Fair Value		$	25,613	$	1,060	—	—	$	26,673

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

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

In the above tables, normal purchases and sales transactions have been excluded. The fair value of the hedge contracts include fair value adjustments reflected in Other Comprehensive Income, Regulatory Assets or Liabilities or Revenues on the Consolidated Statement of Operations.

At Sept. 30, 2004, a 10-percent increase in market prices over the next 12 months for trading contracts would decrease pretax income from continuing operations by approximately $2.1 million, whereas a 10-percent decrease would increase pretax income from continuing operations by approximately $2.2 million.

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 Sept. 30, 2004, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable debt would impact pretax interest expense by approximately $5.3 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 Sept. 30, 2004, a 10-percent increase in prices would have resulted in a net mark-to-market increase in credit risk exposure of $5.5 million, while a decrease of 10-percent would have resulted in a decrease in credit risk exposure of $1.5 million.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2004			2003
Cash provided (used) by operating activities
Continuing operations	$	947		$	788
Discontinued operations	(316		)	215
Total	$	631		$	1,003

Cash provided by operating activities for continuing operations increased by $159 million for the first nine months of 2004, compared with the first nine months of 2003. The increase was primarily due to an increase in the recovery of purchased natural gas and electric energy costs and the timing of payments related to these costs. The 2004 cash used in operating activities for discontinued operations decreased by $531 million and includes the 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.

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2004			2003
Cash provided (used) by investing activities
Continuing operations	$	(838	)	$	(686	)
Discontinued operations	11			95
Total	$	(827	)	$	(591	)

Cash used in investing activities for continuing operations increased by $152 million for the first nine months of 2004, compared with the first nine months of 2003. This is largely due to increased utility capital expenditures partially offset by the availability of previously restricted cash. Cash provided by investing activities for discontinued operations decreased for the first nine months of 2004 by $84 million, compared with the first nine months of 2003 due to receipt of the proceeds from the sale of Viking in January 2003. The discontinued operations for the first nine months of 2004 includes the proceeds from the sale of Xcel Energy International’s Argentina subsidiaries, offset by the $15 million of the sales price placed in escrow.

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2004			2003
Cash used in financing activities
Continuing operations	$	(262	)	$	(222	)
Discontinued operations	—			(10		)
Total	$	(262	)	$	(232	)

Cash used in financing activities for continuing operations increased by approximately $40 million for the first nine months of 2004, compared with the first nine months of 2003. The increase was primarily due to the repurchase of common stock in 2004 for restricted stock awards granted.

Credit Facilities and Other Sources of Liquidity

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

(Millions of Dollars)	Facility		Drawn*		Available		Cash		Liquidity		Maturity
NSP-Minnesota	$	300	$	124	$	176	$	—	$	176	May 2005
PSCo	$	350	$	62	$	288	$	1	$	289	May 2005
SPS	$	125	$	1	$	124	$	—	$	124	Feb. 2005
Xcel Energy – Holding Company	$	400	$	143	$	257	$	—	$	257	Nov. 2005
Total	$	1,175	$	330	$	845	$	1	$	846

* Includes short-term borrowings and letters of credit

The liquidity table above reflects the payment of common dividends on Oct. 20, 2004.

Xcel Energy refinanced its $400-million, 5-year senior unsecured revolving credit facility, which would have matured in November 2005. The new credit facility is a $600-million, 5-year senior unsecured revolving credit facility. The facility provides Xcel Energy with the options to increase the size of the credit facility by $100 million or extend the maturity one year. A financial covenant for debt to total capitalization is included. The new agreement closed on Nov. 4, 2004. The facility will be used for general corporate purposes. See exhibit 10.01 to this Form 10-Q for the full revolving credit facility agreement.

NSP-Wisconsin has approval from the PSCW 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 Oct. 20, 2004, NSP-Wisconsin had $19.4 million of short-term borrowings from NSP-Minnesota and no short-term 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 one financial ratio covenant in the form of a debt to total capitalization ratio.

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 the Wisconsin jurisdiction. Borrowing and lending activity for the utilities in other jurisdictions has commenced. The borrowings or loans outstanding at Sept. 30, 2004 and the SEC approved short-term borrowing limits from the utility money pool are as follows:

	Borrowings (Loans)	Total Borrowing Limits
NSP-Minnesota	—	$	250 million
NSP-Wisconsin	N/A	$	100 million
PSCo	—	$	250 million
SPS	—	$	100 million

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 — Financial Market Risks.

Item 4. CONTROLS AND PROCEDURES

Disclosure 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 SEC rules and forms. As of Sept. 30, 2004, 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 the chief financial officer (CFO), of the effectiveness of our disclosure controls and the procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures are effective.

Internal Controls Over Financial Reporting

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. Xcel Energy has made a number of changes in its internal controls over financial reporting during the most recent fiscal quarter in order to make the control environment more effective and efficient.

Xcel Energy maintains internal control over financial reporting to provide reasonable assurance regarding reliability of our financial reporting. Xcel Energy has evaluated and documented its controls in process activities, in general computer activities, and on an entity-wide level. During the third quarter and in anticipation of issuing its report for the year ended Dec. 31, 2004 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, Xcel Energy conducted testing and monitoring of its internal controls over financial reporting. Based on the control evaluation, testing and remediation performed to date, we have not identified any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board (PCAOB) and approved by the SEC. We have identified several control issues, which if not remediated before year-end, may be determined to be significant deficiencies. Such deficiencies, if any, would be reported to Xcel Energy’s independent external auditors and the audit committee of the board of directors.

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 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. 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 6. Exhibits

The following Exhibits are filed with this report:

* Indicates incorporation by reference.

10.01		Credit agreement between Xcel Energy Inc. and JPMorgan Chase Bank, Barclays Bank PLC and other financial institutions, dated Nov. 4, 2004.
31.01		Principal Executive Officer’s and Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as 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.
99.02		Xcel Energy Inc. and Subsidiaries Consolidated Statements of Operations, as restated for discontinued operations, for the quarters ended March 31, 2003, June 30, 2003, Sept. 30, 2003 and Dec. 31, 2003.

Minnesota		41-0448030
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

800 Nicollet Mall, Minneapolis, Minn.		55402
(Address of principal executive offices)		(Zip code)

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

Class		Outstanding at Oct. 27, 2004
Common Stock, $2.50 par value		400,339,725 shares

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 6. Exhibits
SIGNATURES

	XCEL ENERGY INC.
	(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

Nov. 8, 2004