PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

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,
	2005			2004			2005			2004
Operating revenues:
Electric utility	$	2,063,368		$	1,773,026		$	5,318,573		$	4,707,620
Natural gas utility	207,220			189,895			1,368,622			1,221,253
Nonregulated and other	15,535			12,014			53,344			55,035
Total operating revenues	2,286,123			1,974,935			6,740,539			5,983,908

Operating expenses:
Electric fuel and purchased power — utility	1,121,154			888,845			2,794,791			2,290,560
Cost of natural gas sold and transported — utility	127,493			111,185			1,028,317			891,778
Cost of sales — nonregulated and other	3,745			1,563			17,163			19,802
Other operating and maintenance expenses — utility	400,748			378,758			1,240,857			1,165,293
Other operating and maintenance expenses — nonregulated	4,913			6,620			21,145			18,737
Depreciation and amortization	189,798			176,477			575,468			519,491
Taxes (other than income taxes)	73,547			73,653			220,634			219,880
Total operating expenses	1,921,398			1,637,101			5,898,375			5,125,541
Operating income	364,725			337,834			842,164			858,367

Interest and other income — net of nonoperating expense (see Note 8)	1,930			(562		)	4,365			(1,837		)
Allowance for funds used during construction - equity	4,265			7,400			14,897			24,084

Interest charges and financing costs:
Interest charges — includes other financing costs of $6,426, $6,355, $19,322 and $20,786, respectively	117,449			110,919			345,459			335,153
Allowance for funds used during construction - debt	(4,979		)	(5,916		)	(14,347		)	(17,169		)
Total interest charges and financing costs	112,470			105,003			331,112			317,984
Income from continuing operations before income taxes	258,450			239,669			530,314			562,630
Income taxes	60,633			73,972			130,241			162,575
Income from continuing operations	197,817			165,697			400,073			400,055
Income from discontinued operations — net of tax (see Note 2)	(1,798		)	(118,977		)	830			(117,119		)
Net income	196,019			46,720			400,903			282,936
Dividend requirements on preferred stock	1,060			1,060			3,180			3,180
Earnings available to common shareholders	$	194,959		$	45,660		$	397,723		$	279,756

Weighted average common shares outstanding (thousands):
Basic	402,735			399,746			402,028			399,184
Diluted	426,085			423,078			425,368			422,517
Earnings per share — basic:
Income from continuing operations	$	0.49		$	0.41		$	0.99		$	0.99
Discontinued operations	(0.01		)	(0.30		)	0.00			(0.29		)
Earnings per share — basic	$	0.48		$	0.11		$	0.99		$	0.70
Earnings per share — diluted:
Income from continuing operations	$	0.47		$	0.40		$	0.96		$	0.97
Discontinued operations	0.00			(0.28		)	0.00			(0.28		)
Earnings per share — diluted	$	0.47		$	0.12		$	0.96		$	0.69

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,
	2005			2004
Operating activities:
Net income	$	400,903		$	282,936
Remove income from discontinued operations	(830		)	117,119
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	582,126			544,928
Nuclear fuel amortization	32,436			33,691
Deferred income taxes	179,078			91,509
Amortization of investment tax credits	(8,715		)	(9,166		)
Allowance for equity funds used during construction	(14,897		)	(24,084		)
Undistributed equity in earnings of unconsolidated affiliates	(730		)	1,129
Write down of assets	2,887			—
Unrealized loss on derivative financial instruments	6,868			4,303
Change in accounts receivable	(103,273		)	15,739
Change in inventories	(64,141		)	(51,924		)
Change in other current assets	24,143			(29,754		)
Change in accounts payable	111,064			(28,193		)
Change in other current liabilities	2,146			(12,032		)
Change in other noncurrent assets	(16,505		)	(26,287		)
Change in other noncurrent liabilities	19,957			48,480
Operating cash flows provided by (used in) discontinued operations	157,872			(326,962		)
Net cash provided by operating activities	1,310,389			631,432

Investing activities:
Utility capital/construction expenditures	(897,016		)	(856,506		)
Allowance for equity funds used during construction	14,897			24,084
Investments in external decommissioning fund	(60,436		)	(60,435		)
Nonregulated capital expenditures and asset acquisitions	(4,926		)	(196		)
Proceeds on sale of projects	11,228			—
Restricted cash	(13,906		)	44,242
Other investments — net	9,339			11,282
Investing cash flows provided by discontinued operations	72,361			10,584
Net cash used in investing activities	(868,459		)	(826,945		)

Financing activities
Short-term borrowings —net	(4,300		)	13,437
Proceeds from issuance of long-term debt	373,908			139,000
Repayment of long-term debt, including reacquisition premiums	(397,623		)	(150,727		)
Proceeds from issuance of common stock	6,763			4,470
Repurchase of common stock	—			(32,023		)
Dividends paid	(255,413		)	(235,650		)
Financing cash flows used in discontinued operations	(200		)	(200		)
Net cash used in financing activities	(276,865		)	(261,693		)

Net (decrease) increase in cash and cash equivalents	165,065			(457,206		)
Net decrease in cash and cash equivalents -discontinued operations	(2,750		)	(21,002		)
Net increase in cash and cash equivalents —adoption of FIN No. 46	—			2,303
Cash and cash equivalents at beginning of year	23,361			560,734
Cash and cash equivalents at end of quarter	$	185,676		$	84,829

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

	Sept. 30, 2005			Dec. 31, 2004
ASSETS
Current assets:
Cash and cash equivalents	$	185,676		$	23,361
Accounts receivable — net of allowance for bad debts of $36,982 and $34,299, respectively	864,536			761,264
Accrued unbilled revenues	491,687			435,431
Materials and supplies inventories — at average cost	157,872			161,323
Fuel inventory — at average cost	63,803			64,265
Natural gas inventories - at average cost	283,018			214,964
Recoverable purchased natural gas and electric energy costs	257,982			264,628
Derivative instruments valuation — at market	551,428			129,218
Prepayments and other	110,189			149,538
Current assets held for sale and related to discontinued operations	227,937			367,248
Total current assets	3,194,128			2,571,240
Property, plant and equipment, at cost:
Electric utility plant	18,731,176			18,236,957
Natural gas utility plant	2,705,910			2,617,552
Common utility and other	1,622,318			1,476,553
Construction work in progress	657,369			721,335
Total property, plant and equipment	23,716,773			23,052,397
Less accumulated depreciation	(9,375,120		)	(9,050,636		)
Nuclear fuel — net of accumulated amortization: $1,177,536 and $1,145,228, respectively	86,665			74,308
Net property, plant and equipment	14,428,318			14,076,069
Other assets:
Investments in unconsolidated affiliates	48,134			55,093
Nuclear decommissioning fund and other investments	1,065,151			968,388
Regulatory assets	1,127,679			850,636
Derivative instruments valuation — at market	395,880			424,786
Prepaid pension asset	673,774			642,873
Other	176,038			175,174
Noncurrent assets held for sale and related discontinued operations	429,777			540,584
Total other assets	3,916,433			3,657,534
Total assets	$	21,538,879		$	20,304,843

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	540,715		$	223,655
Short-term debt	308,000			312,300
Accounts payable	1,023,021			903,609
Taxes accrued	213,795			216,439
Dividends payable	87,679			83,405
Derivative instruments valuation — at market	116,913			135,098
Other	350,953			348,557
Current liabilities held for sale and related to discontinued operations	169,559			112,931
Total current liabilities	2,810,635			2,335,994
Deferred credits and other liabilities:
Deferred income taxes	2,144,383			2,065,665
Deferred investment tax credits	134,307			143,028
Regulatory liabilities	2,242,624			1,630,545
Derivative instruments valuation — at market	640,625			450,883
Asset retirement obligations	1,143,832			1,091,089
Customer advances	305,941			303,928
Minimum pension liability	63,967			62,669
Benefit obligations and other	397,635			327,662
Noncurrent liabilities held for sale and related to discontinued operations	8,949			89,242
Total deferred credits and other liabilities	7,082,263			6,164,711
Minority interest in subsidiaries	4,430			3,220
Commitments and contingent liabilities (see Note 5)
Capitalization:
Long-term debt	6,158,538			6,353,020
5-year, senior unsecured credit facilities	-			140,000
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: 2005 — 402,881,570; 2004 — 400,461,804	5,378,033			5,202,918
Total liabilities and equity	$	21,538,879		$	20,304,843

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								Accumulated
	Number of Shares	Par Value		Capital in Excess of Par Value		Retained Earnings (Deficit)			Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Three months ended Sept. 30, 2004 and 2005
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 adjustments									(37		)	(37		)
After-tax unrealized and realized losses related to derivatives -net (see Note 7)									(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

Balance at June 30, 2005	402,358	$	1,005,894	$	3,940,209	$	429,518		$	(128,231	)	$	5,247,390
Net income						196,019						196,019
Minimum pension liability									—			—
After-tax unrealized and realized gains related to derivatives - net (see Note 7)									12,233			12,233
Unrealized gain on marketable securities									2			2
Comprehensive income for the period												208,254
Dividends declared: Cumulative preferred stock of Xcel Energy						(1,060		)				(1,060		)
Common stock						(86,618		)				(86,618		)
Issuances of common stock — net proceeds	524	1,310		8,757								10,067
Balance at Sept. 30, 2005	402,882	$	1,007,204	$	3,948,966	$	537,859		$	(115,996	)	$	5,378,033

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											Accumulated
	Number of Shares		Par Value			Capital in Excess of Par Value			Retained Earnings (Deficit)			Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Nine months ended Sept. 30, 2004 and 2005
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 7)												(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 proceeds	2,747		6,868			39,857									46,725
Purchase for restricted stock issuance	(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

Balance at Dec. 31, 2004	400,462		$	1,001,155		$	3,911,056		$	396,641		$	(105,934	)	$	5,202,918
Net income									400,903						400,903
Minimum pension liability												220			220
After-tax unrealized and realized losses related to derivatives - net (see Note 7)												(10,278		)	(10,278		)
Unrealized loss on marketable securities												(4		)	(4		)
Comprehensive income for the period															390,841
Dividends declared: Cumulative preferred stock of Xcel Energy									(3,180		)				(3,180		)
Common stock									(256,505		)				(256,505		)
Issuances of common stock - net proceeds	2,420		6,049			37,910									43,959
Balance at Sept. 30, 2005	402,882		$	1,007,204		$	3,948,966		$	537,859		$	(115,996	)	$	5,378,033

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) as of Sept. 30, 2005, and Dec. 31, 2004; the results of its operations and changes in stockholders’ equity for the three and nine months ended Sept. 30, 2005 and 2004; and its cash flows for the nine months ended Sept. 30, 2005 and 2004. Due to the seasonality of Xcel Energy’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.

The significant accounting policies followed by Xcel Energy are set forth in Note 1 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2004. The following notes should be read in conjunction with such policies and other disclosures in the Annual Report on Form 10-K.

1. Significant Accounting Policies

FASB Interpretation No. 47 (FIN No. 47) — In April 2005, the Financial Accounting Standards Board (FASB) issued FIN No. 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations pursuant to Statement of Financial Accounting Standard (SFAS) No. 143 - “Accounting for Asset Retirement Obligations”. The interpretation requires that a liability be recorded for the fair value of an asset retirement obligation, if the fair value is estimable, even when the obligation is dependent on a future event. FIN No. 47 further clarified that uncertainty surrounding the timing and method of settlement of the obligation should be factored into the measurement of the conditional asset retirement obligation rather than affect whether a liability should be recognized. Implementation is required to be effective no later than the end of fiscal years ending after Dec. 15, 2005. Additionally, FIN No. 47 will permit but not require restatement of interim financial information during any period of adoption. Both recognition of a cumulative change in accounting and disclosure of the liability on a pro forma basis are required for transition purposes. Xcel Energy is evaluating the impact of FIN No. 47; however, it is not expected to have a material impact on results of operations or financial position due to the expected recovery in customer rates.

Accounting for Uncertain Tax Positions — On July 14, 2005, the FASB issued an exposure draft on accounting for uncertain tax positions under SFAS No. 109 — “Accounting for Income Taxes”. See Note 3 to the consolidated financial statements for further discussion.

Reclassifications — Certain items in the statements of operations have been reclassified from prior period presentation to conform to the 2005 presentation. These reclassifications had no effect on net income or earnings per share. The reclassifications were primarily related to the presentation of Utility Engineering operations as discontinued following the announcement of its sale in March 2005, as discussed below.

2. Discontinued Operations

A summary of the subsidiaries presented as discontinued operations is presented 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 2004 have been restated to conform to the 2005 discontinued operations presentation.

Regulated Utility Segments

During 2004, Xcel Energy reached an agreement to sell its regulated electric and natural gas subsidiary, Cheyenne Light, Fuel and Power Company (CLF&P). The sale was completed on Jan. 21, 2005.

Nonregulated Subsidiaries — All Other Segment

Utility Engineering - In March 2005, Xcel Energy agreed to sell its non-regulated subsidiary, Utility Engineering Corp. (UE), to Zachry Group, Inc. In April 2005, Zachry acquired all of the outstanding shares of UE. Xcel Energy recorded an immaterial loss in the first quarter of 2005 as a result of the transaction. In August 2005, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Quixx Corp., a former subsidiary of UE that partners in cogeneration projects that was not included in the sale of UE to Zachry.

Seren — On Sept. 27, 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren Innovations, Inc. (Seren), a wholly owned broadband communications services subsidiary. Seren delivers cable television, high-speed Internet and telephone service over an advanced network to approximately 46,000 customers in St. Cloud, Minn., and Concord and Walnut Creek, Calif.

On May 25, 2005, Xcel Energy reached an agreement to sell Seren’s California assets to WaveDivision Holdings, LLC, which is expected to close in the fourth quarter of 2005. In July 2005, Xcel Energy reached an agreement to sell Seren’s Minnesota assets to Charter Communications, which is expected to be completed in the first quarter of 2006. Xcel Energy recorded an estimated asset impairment of $143 million in 2004. Based on the sales agreements entered into in 2005, the estimate was adjusted in 2005 to reflect a total asset impairment of $138 million.

Xcel Energy International and e prime — By the third quarter of 2004, Xcel Energy had exited all business conducted by its nonregulated subsidiary, e prime, inc., and most conducted by Xcel Energy International Inc.

Summarized Financial Results of Discontinued Operations

(Thousands of dollars)	Utility Segments		All Other			Total

Three months ended Sept. 30, 2005
Operating revenue	$	—	$	15,183		$	15,183
Operating and other expenses	—		19,931			19,931
Pretax income (loss) from operations of discontinued components	—		(4,748		)	(4,748		)
Income tax expense (benefit)	—		(2,950		)	(2,950		)
Net income (loss) from discontinued operations	$	—	$	(1,798	)	$	(1,798	)

Three months ended Sept. 30, 2004
Operating revenue and equity in project income	$	23,155	$	60,070		$	83,225
Operating and other expenses	22,724		244,413			267,137
Other income (loss)	295		(6,012		)	(5,717		)
Pretax income (loss) from operations of discontinued components	726		(190,355		)	(189,629		)
Income tax expense (benefit)	276		(70,928		)	(70,652		)
Net income (loss) from operations of discontinued components	$	450	$	(119,427	)	$	(118,977	)

(Thousands of dollars)	Utility Segments		All Other			Total

Nine months ended Sept. 30, 2005
Operating revenue	$	6,579	$	49,498		$	56,077
Operating and other expenses	6,131		50,488			56,619
Pretax income (loss) from operations of discontinued components	448		(990		)	(542		)
Income tax expense (benefit)	268		(1,640		)	(1,372		)
Net income from discontinued operations	$	180	$	650		$	830

Nine months ended Sept. 30, 2004
Operating revenue and equity in project income	$	68,399	$	174,067		$	242,466
Operating and other expenses	65,511		367,293			432,804
Other income (loss)	—		(5,645		)	(5,645		)
Pretax income (loss) from operations of discontinued components	2,888		(198,871		)	(195,983		)
Income tax expense (benefit)	1,004		(79,868		)	(78,864		)
Net income (loss) from operations of discontinued components	$	1,884	$	(119,003	)	$	(117,119	)

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

(Thousands of dollars)	Sept. 30, 2005			Dec. 31, 2004

Cash	$	24,078		$	33,228
Restricted cash	—			15,000
Trade receivables — net	5,828			24,364
Deferred income tax benefits	186,007			234,305
Other current assets	12,024			60,351
Current assets held for sale	227,937			367,248
Property, plant and equipment — net	60,645			155,428
Deferred income tax benefits	326,602			338,863
Other noncurrent assets	42,530			46,293
Noncurrent assets held for sale	429,777			540,584
Current portion of long-term debt	—			—
Accounts payable — trade	12,102			29,451
Other current liabilities	157,457			83,480
Current liabilities held for sale	169,559			112,931
Long-term debt	—			24,800
Other noncurrent liabilities	8,949			64,442
Noncurrent liabilities held for sale	$		8,949	$	89,242

NRG - In December 2003, Xcel Energy divested its ownership interest in NRG Energy Inc. (NRG), a former independent power production subsidiary that had filed for bankruptcy protection in May 2003. Changes in the accounting estimates of Xcel Energy’s NRG-related tax benefits may continue to occur in the future as better information becomes available regarding the treatment of the divestiture transaction by tax authorities. Cash flows from receipt of NRG-related deferred income tax benefits did occur in 2003 and 2004, and will continue in the future as tax loss carryforwards related to the investment in and financial results of NRG are utilized on Xcel Energy’s tax returns. Xcel Energy expects to use $100 million of these tax benefits in 2005. Approximately $414 million of deferred tax benefits related to NRG are included in discontinued operations assets listed above as of Sept. 30, 2005. In addition, payments to NRG creditors under the NRG bankruptcy settlement are included in Xcel Energy’s cash flows from discontinued operations in the statement of cash flows for the nine months ended Sept. 30, 2004.

3. Tax Matters — Corporate-Owned Life Insurance

Interest Expense Deductibility — As previously disclosed, in April 2004, Xcel Energy filed a lawsuit in U.S. District Court for the District of Minnesota against the Internal Revenue Service (IRS) to establish its entitlement to deduct, for tax years 1993 and 1994, policy loan interest related to corporate-owned life insurance (COLI) policies on some of the employees of Public Service Company of Colorado (PSCo). These COLI policies are owned and managed by PSR Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo. In December 2004, Xcel Energy filed suit in U.S. Tax Court in Washington D.C. for tax years 1995 through 1997 and again in March 2005 for tax years 1998 and 1999. The IRS had challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through 2001. Xcel Energy anticipates that the Tax Court actions will be held in abeyance pending the resolution of the litigation that Xcel Energy has commenced in the District Court.

On May 2, 2005, Xcel Energy filed a motion for summary judgment in the district court litigation, which summary judgment motion asserted that Xcel Energy is entitled, as a matter of law, to deduct the policy loan interest. On June 22, 2005, the government also filed a summary judgment motion arguing that Xcel Energy lacked an insurable interest in the lives of its employees, and therefore, the policies were allegedly void. Both motions were heard in district court on August 19, 2005.

On Oct. 12, 2005, the District Court issued its order denying Xcel Energy’s motion for summary judgment because the court found the existence of disputed issues of fact that could only be resolved by a trial. It also denied the government’s motion for summary judgment, which asserted that Xcel Energy had no insurable interest in the lives of its employees. The District Court did grant partial summary judgment to Xcel Energy affirming that it had an insurable interest in the lives of its employees. The case is expected to proceed to trial, and the litigation could require several years to reach final resolution, if the District Court decision is appealed.

Xcel Energy contends that the IRS position 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. As discussed above, the litigation could require several years to reach final resolution. Defense of Xcel Energy’s position may require cash outlays, which may or may not be recoverable in a court proceeding. Although the ultimate resolution of this matter is uncertain, it could have a material adverse effect on Xcel Energy’s financial position, results of operations and cash flows.

Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2005, would reduce earnings by an estimated $350 million. The government has counterclaimed in the District Court action for a 20 percent accuracy-related penalty and has also asserted similar penalties for the tax years that are the subject of the two Tax Court actions. Including penalties, the total exposure through Dec. 31, 2005 is approximately $415 million. Xcel Energy estimates its annual earnings for 2005 would be reduced by $40 million, after tax, which represents 9 cents per share, if COLI interest expense deductions were no longer available.

Accounting for Uncertain Tax Positions — In 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 that have some degree of uncertainty. On July 14, 2005, the FASB issued an exposure draft on accounting for uncertain tax positions under SFAS No. 109. As issued, the exposure draft would have been effective Dec. 31, 2005 and only tax benefits that meet the probable recognition threshold may be recognized or continue to be recognized on the effective date. Initial derecognition amounts will be reported as a cumulative effect of a change in accounting principle.

Accordingly, as proposed under the exposure draft, Xcel Energy would report as a cumulative effect of a change in accounting principle in its income statement for the year ended Dec. 31, 2005 a charge of approximately $350 million relating to COLI tax benefits and additional interest costs. Under the exposure draft, penalties are to be accrued when a tax position does not meet the minimum statutory threshold. Xcel Energy believes the COLI position exceeds the minimum statutory threshold and, therefore, does not expect to accrue penalties under the interpretation. However, if penalties were required to be accrued, they would be approximately $65 million. Xcel Energy has not yet evaluated the impact the proposed interpretation would have on other existing income tax positions. The FASB has announced that the effective date of the new rules will be delayed, with a revised pronouncement to be released no earlier than the first quarter of 2006.

4. Rates and Regulation

Federal Regulation

Energy Legislation — On Aug. 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (Energy Act), significantly changing many federal energy statutes. The Energy Act is expected to have a substantial long-term effect on energy markets, energy investment, and regulation of public utilities and holding company systems by the Federal Energy Regulatory Commission (FERC), the Securities and Exchange Commission (SEC) and the United States Department of Energy (DOE). The FERC was directed by the Energy Act to address many areas previously regulated by other governmental entities under the statutes and determine whether changes to such previous regulations are warranted. The issues that the FERC has been required to consider associated with the repeal of the Public Utility Holding Company Act of 1935 include the expansion of the FERC authority to review mergers and sales of public utility companies and the expansion of the FERC authority over the books and records of public utility companies previously governed by the SEC. The FERC is in various stages of rulemaking on these and other issues. Xcel Energy cannot predict the impact the new rulemaking will have on its operations or financial results, if any.

Market-Based Rate Authority — The FERC regulates the wholesale sale of electricity. In order to obtain market-based rate authorization from the FERC, utilities such as the utility subsidiaries of Xcel Energy have been required to submit analyses demonstrating that they did not have market power in the relevant markets. Xcel Energy and its utility subsidiaries were previously granted market-based rate authority by the FERC. The utility subsidiaries include Northern States Power Co., a Minnesota corporation (NSP-Minnesota), Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin), PSCo and Southwestern Public Service Co. (SPS), which are collectively referred to as the Utility Subsidiaries.

In 2004, the FERC adopted two indicative screens (an uncommitted pivotal supplier analysis and an uncommitted market share analysis) as a revised test 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 filed the required analysis applying the FERC’s two indicative screens on behalf of itself and the Utility Subsidiaries with the FERC on Feb. 7, 2005. This analysis demonstrated that all of the Utility Subsidiaries, with the exception of PSCo, passed the pivotal supplier analysis in their own control areas and all adjacent markets, but that all failed the market share analysis in their own control areas, and in the case of NSP-Minnesota and NSP-Wisconsin, which jointly operate a single control area and accordingly are analyzed as one company, in certain adjacent markets. Numerous parties filed interventions and requested that the FERC set the analysis for hearing. Certain parties asked the FERC to revoke the market-based rate authority of the Utility Subsidiaries.

On June 2, 2005, the FERC issued an order initiating a proceeding pursuant to Section 206 of the Federal Power Act to investigate PSCo’s and SPS’ market-based rate authority within their own control areas. The refund effective date that has been set as part of that investigation for such sales is Aug. 12, 2005. Because of the commencement of the Midwest Independent Transmission System Operator, Inc. (MISO) Day 2 market, discussed below, and the FERC’s decision consistent with other precedent to analyze NSP-Minnesota and NSP-Wisconsin as part of that larger market, the FERC is not addressing NSP-Minnesota’s and NSP-Wisconsin’s market power in that investigation. The FERC did require that Xcel Energy make a compliance filing providing information, including information regarding the FERC’s affiliate abuse component of its market power analysis and the allegations regarding that component made by an intervenor within 30 days of the date of issuance of its order. The latter compliance filing was submitted on July 5, 2005.

On Aug. 1, 2005, SPS and PSCo submitted a filing to withdraw their market-based rate authority with respect to sales within their control areas. As part of that filing, SPS and PSCo proposed to charge existing cost-based rates for sales into the SPS and PSCo control areas. In October 2005, PSCo and SPS filed revised tariff sheets to reflect that limitation on their market-based rate authority. Notwithstanding these actions, certain intervenors are still contending that the FERC must hold an investigation regarding SPS’ market power and the rates that SPS is proposing to charge where it has relinquished market-based rate authority. The matter is pending before the FERC.

California Refund Proceeding — As previously disclosed in the Xcel Energy Annual Report on Form 10-K for the year ended Dec. 31, 2004, there are a number of proceedings before the FERC relating to the price of sales into the California electricity markets from May 1, 2000 through June 20, 2001. In September 2005, PSCo reached an agreement with respect to these proceedings with a group of California entities including: San Diego Gas & Electric Company, Pacific Gas and Electric Company, Southern California Edison Company, the California Department of Water Resources, the California Public Utilities Commission and the California Attorney General. Pending approval of the settlement by the FERC, PSCo will pay approximately $5.5 million in cash and assign $1.8 million in accounts receivable from the California Independent System Operator and the California Power Exchange to the settling participants. In 2004, PSCo reserved approximately $7 million related to this proceeding. The settlement, which includes no acknowledgment of wrongdoing by PSCo, avoids further costly litigation and resolves all claims by PSCo against the settling participants and by the settling participants against PSCo. While accounting for approximately 90 percent of purchases in the California markets, the California utilities were not the only purchasers in those markets. However, the settlement makes provision for other purchasers to opt into the settlement. At this time, the settlement is pending approval at the FERC, and other purchasers in the California markets still may exercise their right to join the settlement. Xcel Energy does not anticipate that resolving the issues with the non-settling purchasers, either through their prospective acceptance of the settlement or through other means, will significantly impact the results of operations.

PSCo and SPS FERC Transmission Rate Case — On Sept. 2, 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 (OATT). PSCo and SPS requested 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, their power sales rates would be reduced by $1.4 million. The net increase in annual revenues proposed is $4.7 million, of which $3.0 million is attributable to PSCo. The FERC suspended the filing and delayed the effective date of the proposed increase to June 1, 2005. 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, which would provide annual rate changes reflecting changes in cost and usage. The case is currently pending settlement judge procedures and interim rates went into effect on June 1, 2005, subject to refund.

SPS Wholesale Rate Complaints — In November 2004, several wholesale cooperative customers of SPS filed a $3 million rate complaint at the FERC requesting that the FERC investigate SPS’ wholesale power base rates and fuel clause calculations. In December 2004, the FERC accepted the complaint filing and ordered SPS base rates subject to refund, effective January 1, 2005. Also in November 2004, SPS filed revisions to its wholesale fuel cost adjustment clause. The FERC set the proposed rate changes into effect on January 1, 2005, subject to refund, and consolidated the proceeding with the wholesale cooperative customers’ complaint proceeding. The FERC set the consolidated proceeding for hearing and settlement judge procedures, which were terminated when the parties could not reach a settlement. A hearing judge has been appointed by the FERC and hearings are

scheduled for December 2005.

On Sept. 15, 2005, Public Service Company of New Mexico (PNM) filed a separate complaint at the FERC in which it contended that its demand charge under an existing interruptible power supply contract with SPS is excessive and that SPS has overcharged PNM for fuel costs under three separate agreements through erroneous fuel clause calculations. PNM’s arguments mirror those that it made as an intervenor in the cooperatives’ complaint case, and SPS believes that they have little merit. SPS submitted a response to PNM’s complaint in October 2005, and the case is pending FERC action.

Independent Transmission System Operators

MISO Operations (NSP-Minnesota and NSP-Wisconsin) —MISO initiated the Day 2 wholesale market on April 1, 2005, including locational marginal pricing. While it is anticipated that the Day 2 market will provide short-term efficiencies through a region-wide generation dispatch and increased reliability, as well as long-term benefits through dispatch of power from the most cost-effective sources of generation or transmission, there are costs associated with Day 2. NSP-Minnesota and NSP-Wisconsin have requested recovery of these costs within their respective jurisdictions.

Within MISO, an independent market monitor reviews market bids and prices to identify any unusual activity. This market monitor identified a number of such unusual items during the initial period of Day 2 operations. These items were referred to the FERC, which investigated the issues. These initial investigations were closed in July 2005. While there has been no further action on these initial investigations, the FERC has notified Xcel Energy that it is investigating other pricing issues. Xcel Energy and other market participants continue to work with MISO, the independent market monitor and the FERC to resolve Day 2 market implementation issues such as dispatch methods and settlement calculation details. Xcel Energy also intends to work with these parties to resolve any identified pricing issues.

On Sept. 2, 2005, MISO notified market participants that it had corrected the method of calculating Over Collected Losses. This change will be applied retroactively to the market start date. This change will also impact other charge calculations. MISO completed the resettlement and rebilling effort associated with this issue in October. Settlements are expected in fourth quarter of 2005. Xcel Energy has accrued an estimated impact of this issue and has sought recovery where appropriate. The ultimate effect of the rebilling and re-settlement effort is not completely known at this time, but based on the cost recovery mechanisms in place in the operating utility jurisdictions, it is not expected to have a material impact on the results of operations.

New business processes, systems and internal controls over financial reporting were planned and implemented by Xcel Energy and MISO during the second quarter of 2005 to conduct business within the MISO Day 2 market. Xcel Energy continues to validate these changes and to review the energy costs and revenues determined by MISO. In August 2005, the MISO released an independent audit opinion concluding that the design and operating effectiveness of its internal controls related to the market settlement processes and information systems were suitably designed and operated with sufficient effectiveness during the period April 1, 2005 through May 31, 2005. Supplementing this report, the MISO released an Internal Controls Disclosure Certificate dated Oct. 12, 2005 internally certifying the continuing effectiveness of its controls. While neither the design nor operating effectiveness of the MISO control environment have been disputed, Xcel Energy and other market participants have disputed certain transactions.

MISO Cost Recovery (NSP-Minnesota and NSP-Wisconsin) — On Dec. 18, 2004, NSP-Minnesota filed with the Minnesota Public Utilities Commission (MPUC) a petition to seek recovery of the Minnesota jurisdictional portion of all net costs associated with the implementation of the MISO Day 2 market through its fuel clause adjustment (FCA) mechanism. In April 2005, the MPUC issued an order allowing NSP-Minnesota to recover these costs through the FCA effective April 1, 2005, on an interim basis, subject to refund, pending a later decision on the merits when the full record of the case is developed. A decision on the merits is expected later in 2005.

In addition, in March 2005, NSP-Minnesota filed similar petitions with the North Dakota Public Service Commission (NDPSC) and the South Dakota Public Utilities Commission (SDPUC) proposing changes to allow recovery of the applicable North Dakota and South Dakota jurisdictional portions of the MISO Day 2 market costs. The SDPUC approved the proposed tariff changes effective April 1, 2005, as requested. The NDPSC granted interim recovery through the FCA beginning April 1, 2005, but similar to the decision of the MPUC, conditioned the relief as being subject to refund until the merits of the case are determined. A decision on the merits is expected later in 2005.

On March 29, 2005, NSP-Wisconsin received an order from the Public Service Commission of Wisconsin (PSCW) granting its requests to defer the costs and benefits attributable to the start-up of the MISO Day 2 energy market. NSP-Wisconsin also received an order granting its request to record energy market transactions on a net basis. The netting of transactions is consistent with the approach envisioned by the FERC in approving the transmission and energy markets tariff and is consistent with generally accepted

accounting principles. On Sept. 22, 2005, the PSCW opened an investigation to obtain information from interested persons related to MISO policy development that is beneficial to ratepayers and that protects the public interest. On Oct. 18, 2005, the PSCW solicited comments on the PSCW staff proposal regarding rate and accounting treatment of MISO revenues and costs, as well as a request to escrow MISO Day 2 energy market costs until 2008. NSP-Wisconsin will continue to work with the PSCW and other utilities to address the longer-term issue related to MISO policies.

Wisconsin Public Service Corp. Complaints (NSP-Minnesota and NSP-Wisconsin) - In December 2004, Wisconsin Public Service Corp. (WPS) filed a complaint against MISO at FERC alleging that MISO improperly awarded NSP-Minnesota certain financial transmission rights under the MISO Day 2 market for certain partial path transmission services. Xcel Energy intervened and protested the complaint. The partial path transmission rights had also been the subject of a prior complaint by WPS in 2003 that FERC denied, a decision WPS appealed. In late April 2005, FERC dismissed the 2004 WPS complaint, but the D.C. Circuit Court of Appeals vacated and remanded the 2003 complaint order to FERC. In June 2005, WPS, MISO and Xcel Energy reached a settlement of the disputed matters. On July 22, 2005, the FERC issued an order approving the settlement. The settlement resolves the uncertainty related to the regulatory litigation.

MISO Long Term Transmission Pricing (NSP-Minnesota and NSP-Wisconsin) - On Oct. 7, 2005, MISO filed proposed tariff revisions that would allow MISO to regionalize the cost of certain future high voltage transmission lines owned by individual transmission owners but constructed pursuant to the MISO transmission expansion plan. The proposed tariffs reflect the stakeholder input to MISO through the Regional Expansion Capacity Benefits task force. MISO proposes the tariff revisions be effective on Feb. 4. 2006. Xcel Energy generally supports the proposed tariff revisions, which should encourage transmission construction by regionalizing a share of the cost of projects providing regional benefits. Comments on or protests to the proposed tariff revisions will be filed at FERC later in 2005 and no final FERC decision is expected in 2005.

SPP Energy Imbalance Service (SPS) - On June 15, 2005, the Southwest Power Pool (SPP) filed proposed tariff provisions to establish an Energy Imbalance Service (EIS), a wholesale energy market for the SPP region, using a phased approach toward the development of a fully-functional locational marginal pricing energy market with appropriate financial transmission rights. On July 15, 2005, Xcel Energy filed a protest addressing the EIS proposal and urging FERC to reject the proposal and provide guidance to SPP in its effort to design and implement a fully functional Day 2 market for the SPP region to avoid “seams” between the MISO and SPP regions. On Sept. 19, 2005, FERC issued an order rejecting the SPP EIS proposal and providing guidance and recommendations to SPP; however, the FERC did not require SPP to implement a full Day 2 market similar to MISO. Requests for rehearing of the FERC order were due Oct. 19, 2005.

Other Regulatory Matters — Minnesota

NSP-Minnesota Natural Gas Rate Case - In September 2004, NSP-Minnesota filed a natural gas rate case for its Minnesota retail customers, seeking a rate increase of $9.9 million, based on a return on equity of 11.5 percent. In August 2005, the MPUC approved an annual rate increase of $5.8 million, based on a return on equity of 10.4 percent.

NSP-Minnesota Nuclear Plant Re-licensing — On Aug. 25, 2004, the Xcel Energy board of directors authorized the pursuit of renewal of the operating licenses for the Monticello and Prairie Island nuclear plants. Monticello’s current 40-year license expires in 2010, and Prairie Island’s licenses for its two units expire in 2013 and 2014. NSP-Minnesota filed its application for Monticello with the MPUC in January 2005 seeking a certificate of need for dry spent fuel storage. Testimony is expected to be filed in November 2005. Hearings are expected early in 2006. On March 24, 2005, a license renewal application for Monticello was filed with the Nuclear Regulatory Commission (NRC), commencing a 22-month review and approval process necessary for the NRC to grant the 20-year license extension allowed by NRC regulations. Plant assessments and other work for the Prairie Island applications are planned in the next two or three years.

NSP System Resource Plan — On Nov. 1, 2004, NSP-Minnesota filed its 2004 resource plan with the MPUC. The resource plan projects a need for an additional 3,100 megawatts of electricity resources during the next 15 years, based on an anticipated growth in demand of 1.61 percent annually, or approximately 170 megawatts per year, during the period.

The Minnesota Department of Commerce (DOC) endorsed the relicensing of the Prairie Island and Monticello nuclear plants and supported the need for 1,125 megawatts of new base load generating facilities starting in 2015. However, the DOC disputed NSP-Minnesota’s forecast and developed its own forecast that reduces NSP-Minnesota’s estimated demand for electricity by 475 megawatts in 2010, increasing to 710 megawatts by 2015. As a result, the DOC disputes that any additional peaking or intermediate generation is needed on the NSP system over the next 10 years. The DOC also recommended that NSP-Minnesota be required to

increase its wind commitment by 1,120 megawatts starting in 2017, and that it adopt a higher demand-side management goal than the one proposed in the plan.

NSP-Minnesota expects to file its response to the DOC and other parties on Nov. 23, 2005. The response will include a full report on base load development and acquisition efforts to date.

Energy Legislation — The 2005 Minnesota Legislature passed and the Governor signed an Omnibus Energy Bill, effective July 1, 2005. Among other things, the new law provides authority for the MPUC to approve rate rider recovery for transmission investments that have been approved through a certificate of need, the biennial transmission plan, or are associated with compliance with the state’s renewable energy objective. The statute provides that the rate rider may include recovery of the revenue requirement associated with qualifying projects, including a current return on construction work in progress. NSP-Minnesota is currently preparing a filing expected to be made by year-end to the MPUC for approval of a new tariff to implement this statute.

Other Regulatory Matters — Wisconsin

NSP-Wisconsin 2005 Fuel Cost Recovery - On April 22, 2005, NSP-Wisconsin filed an application with the PSCW to increase electric rates by $10 million, or 2.7 percent, annually to provide for recovery of forecasted increased costs of fuel and purchased power over the balance of 2005. The March 2005 actual fuel costs were approximately 13 percent higher than authorized recovery in current base rates, and the forecast for the remainder of 2005 showed costs outside the annual range by 9.6 percent. On May 18, 2005, the PSCW issued an order approving interim rates at the level requested, effective May 19, 2005. At this level, the rate increase will generate an estimated $6.2 million in additional revenue for NSP-Wisconsin in 2005. Under the provisions of the Wisconsin fuel rules, any difference between interim rates and final rates is subject to refund. A public hearing was held on Aug. 23, 2005, and on Sept. 28, 2005, the PSCW issued a final order approving an increase of $11.6 million, or 3.1 percent annually. Because the final rates are slightly higher than interim rates authorized in May 2005, no refund is necessary. With an effective date of Oct. 1, 2005, final rates will collect approximately $400,000 in incremental revenue, as compared to interim rates, over the last three months of 2005. Final rates set in this proceeding will remain in effect until new rates are set in the 2006 rate case proceeding.

On Oct. 14, 2005, NSP-Wisconsin filed an application with the PSCW to increase the amount of the currently authorized surcharge by $8.9 million or 2.3 percent on an annual basis. This additional request was due to dramatic increases in the cost of natural gas and purchased power since the surcharge amount was set in mid-August. September 2005 actual fuel costs were approximately 38 percent higher than authorized recovery in current rates, and the forecast for the remainder of 2005 showed costs outside the annual range by 7.5 percent. A PSCW order was requested on an expedited basis. If approved as requested, effective Nov. 10, 2005, NSP-Wisconsin would collect approximately $1.2 million in additional revenue over the remainder of 2005.

NSP-Wisconsin 2006 General Rate Case - NSP-Wisconsin filed with the PSCW an electric and natural gas rate case, as amended on Sept. 28, 2005, to reflect higher energy costs. The amended filing requested an electric revenue increase of $53.1 million, or 13.4 percent, and a natural gas revenue increase of $7.7 million, or 4.8 percent, based on an 11.9 percent return on equity and a 56.32 percent common equity to total capitalization ratio.

On Oct. 12, 2005, the staff of the PSCW filed testimony recommending that NSP-Wisconsin has a 2006 test year electric revenue deficiency of $45.4 million, or 11.4 percent, and a natural gas revenue deficiency of $5.8 million, or 3.5 percent, based on an 11.0 percent return on equity and a 56.43 percent common equity to total capitalization ratio.

Intervenor testimony was also filed on Oct. 12, 2005. Consultants representing the industrial intervenor group advocated a return on equity of 10.5 percent and a common equity to total capitalization ratio of 51 percent, as well as modifications to NSP-Wisconsin’s class cost of service study and rate design that would benefit their clients. Testimony submitted on behalf of the U.S. Department of Defense and other federal executive agencies advocated a 10.25 percent return on equity and a common equity to total capitalization ratio of 56.3 percent, as well as cost allocations and rate design to benefit the Fort McCoy military installation.

Both the staff of the PSCW and the industrial intervenor group suggested that the PSCW consider whether it should continue to authorize a common equity to total capitalization ratio and return on equity comparable to other A or AA rated Wisconsin utilities or use metrics appropriate to a BBB+ credit rating.

Hearings are scheduled to begin on Nov. 1, 2005, with a decision expected near the end of 2005.

Other Regulatory Matters — Colorado

PSCo Resource Plan — In December 2004, the Colorado Public Utilities Commission (CPUC) approved a settlement agreement between PSCo and many intervening parties concerning PSCo’s future resource plan. The PSCo resource plan identified a need to acquire an additional 3,600 megawatts of electric resources by 2013. Part of the settlement approved by the CPUC is PSCo’s plan to construct a 750-megawatt pulverized coal-fired unit (Comanche 3) at the existing Comanche Station located near Pueblo, Colo. and transfer up to 250 megawatts of capacity ownership to Intermountain Rural Electric Association (IREA) and Holy Cross Energy. PSCo would operate the unit.

PSCo has signed agreements with IREA that define the respective rights and obligations of PSCo and IREA in the transfer of capacity ownership in the Comanche 3 unit. PSCo continues to discuss the possibility of partnership arrangements with Holy Cross Energy.

PSCo has received the following permits or authorizations for construction and operation of Comanche 3:

• Final air quality permits (received July 5, 2005);

• A long-term water supply contract with the Pueblo Board of Water Works (received July 19, 2005);

• Pueblo City Council approval to annex the Comanche plant into the city (received Sept. 12, 2005) and

• Use by Special Review permit for onsite disposal of ash over a 50-year period (received Sept. 27, 2005).

Construction on Comanche 3 began in October 2005. Actual building permits will be requested concurrently with the actual design and construction of the Comanche 3 unit.

On Feb. 24, 2005, PSCo issued an all-source request for proposals for additional resources. PSCo requested proposals for dispatchable resources, non-dispatchable resources and demand-side management resources to begin providing resources in 2006. On May 17, 2005, PSCo received bids for approximately 17,000 megawatts, including proposals for coal-fired generation, gas-fired generation, wind generation, biomass generation and demand-side management. PSCo is in the process of evaluating the bids.

Renewable Portfolio Standards (PSCo) - In November 2004, an amendment to the Colorado statutes was passed requiring implementation of a renewable energy portfolio standard for electric service. The new law requires PSCo to generate, or cause to be generated, a certain level of electricity from eligible renewable resources. Generation of electricity from renewable resources, particularly solar energy, may be a higher-cost alternative to traditional fuels, such as coal and natural gas. Such incremental costs are expected to be recovered from customers. On March 29, 2005, the CPUC initiated a proceeding to determine the rules and regulations required to implement the renewable portfolio standard. The CPUC received numerous rounds of comments with respect to proposed rules, and the CPUC held hearings beginning in August 2005 regarding the rulemaking. The CPUC conducted oral deliberations in early October and determined, among other issues, that compliance with the renewable energy portfolio standard should be measured through the acquisition of renewable energy credits either with or without the accompanying renewable energy, that the utility purchaser owns the renewable energy credits associated with existing contracts where the power purchase agreement is silent on this issue, that Colorado utilities should be required to file implementation plans, thereby rejecting the proposal to use an independent plan administrator, and the methods utilities should use for determining the budget available for renewable resources. The details of these rulings will be set forth in proposed rules, which the CPUC expects to issue in mid-November 2005. Final rules are expected to become effective by the end of this year.

PSCo Natural Gas Rate Case — On May 27, 2005, PSCo filed for an increase of natural gas base rates in Colorado. PSCo’s filing, amended in July 2005, requests an increase in annual revenues of approximately $34.5 million, or 3 percent annually. The filing asks for a return on equity of 11.00 percent with a capital structure consisting of 55.49 percent equity and 44.51 percent debt resulting in an overall return on rate base of 9.01 percent applied to year end rate base.

On Oct. 5, 2005, intervenors began filing testimony regarding the PSCo gas rate case. In its testimony, the staff of the CPUC recommended an increase in annual revenues of approximately $9 million, a return on equity of 9.5 percent and a capital structure consisting of 52.53 percent equity and 47.47 percent debt, resulting in an overall return on rate base of 8.11 percent applied to average rate base.

The Office of Consumer Counsel proposed a decrease in annual revenues of $189,000, a return on equity of 8.5 percent and a capital structure consisting of 50.11 percent equity and 49.89 percent debt, resulting in an overall return on rate base of 7.56 percent applied to average rate base.

Several other parties filed testimony with their proposals to the CPUC. It is anticipated that a decision by the CPUC would become effective early in 2006.

Tie Line Cost Recovery - On Sept. 20, 2001, the CPUC ruled that only 50 percent of the total cost of the high voltage direct current (HVDC) converter constructed by PSCo in Lamar, Colorado will be allowed in rate base. This facility is part of the transmission facilities connecting the PSCo and SPS systems. The CPUC decision resulted in a reduction of potential PSCo rate base of approximately $16.7 million. On April 7, 2005, PSCo filed an application with the CPUC proposing a mechanism that would leave half of the HVDC facility as a non-rate-base asset, but that would generate revenue to recover the cost of the non-rate-base asset on a pay-as-you-go basis. The proposal would involve allocating half of any energy or fuel cost savings derived from buying electricity through the tie line or making sales through the tie line. Alternatively, PSCo stated that it would not object to the entire HVDC facility being placed in rate base. The CPUC staff opposed PSCo’s proposal. A hearing regarding this matter was held in October 2005. A ruling is expected by the end of 2005.

Other Regulatory Matters — Texas

Texas Retail Fuel Cost (SPS) — Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor. In May 2004, SPS filed with the Public Utility Commission of Texas (PUCT) 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 approval of approximately $580 million of Texas-jurisdictional fuel and purchased power costs for the two-year period. Intervenor and PUCT staff testimony was filed in October 2004 and hearings were held in December 2004. Intervenor testimony contained objections to SPS’ methodology for assigning average fuel costs to certain wholesale sales, among other things. Recovery of $49 million to $86 million of the requested amount was contested by multiple intervenors.

The administrative law judge issued his recommended proposal for the decision (PFD) on April 15, 2005, which was generally favorable to SPS. Prior to issuance of the PFD, SPS had entered into a non-unanimous stipulation with the PUCT staff and several of the intervenors. The stipulation would provide reasonable regulatory certainty for SPS on all key issues raised in this proceeding. The deadline for parties to protest the stipulation and request a hearing was July 22, 2005. No parties protested the stipulation. On Oct. 7, 2005, the PUCT issued an order requesting exceptions on the PFD and stipulation and announced it would take both into consideration in making its decision in this proceeding. It is anticipated that a final order will be issued in November 2005. The PUCT order may or may not reflect the terms of the stipulation or the PFD. The stipulation reflects a potential liability of approximately $25 million, which is consistent with the reserve that SPS accrued during the fourth quarter of 2004 related to this proceeding. SPS believes this estimate is appropriate and sufficient.

Energy Legislation - The 2005 Texas Legislature passed and the Governor signed, effective June 18, 2005, a law establishing statutory authority for electric utilities outside of the electric reliability council of Texas in the SPP or the Western Electricity Coordinating Council to have timely recovery of transmission infrastructure investments. After notice and hearing, the PUCT may allow recovery on an annual basis of the reasonable and necessary expenditures for transmission infrastructure improvement costs and changes in wholesale transmission charges under a tariff approved by FERC. The PUCT will initiate a rulemaking for this process that is expected to take place largely in the first quarter of 2006.

Other Regulatory Matters — New Mexico

New Mexico Fuel Review (SPS) - On Jan. 28, 2005, the New Mexico Public Regulatory Commission (NMPRC) accepted the staff petition for a review of SPS’ fuel and purchased power cost. The staff has requested a formal review of SPS’ fuel and purchased power cost adjustment clause (FPPCAC) for the period of Oct. 1, 2001 through August 2004. Several parties have requested to expand the issues in the case. The NMPRC decided not to expand the case and address any additional issues in SPS’ fuel continuation case filed in August 2005. Hearings in the fuel review case have been scheduled for April 2006.

New Mexico Fuel Factor Continuation Filing (SPS) - The filing to continue the use of SPS’ FPPCAC was filed on Aug. 18, 2005. This filing is required every two years pursuant to the NMPRC rules. The filing proposes that the FPPCAC continue the current monthly factor cost recovery methodology. Certain industrial customers have asked the NMPRC to review SPS’ assignment of system average fuel cost to certain wholesale capacity sales. Customers have also asked the NMPRC to investigate the treatment of renewable energy credits and sulfur dioxide allowance credit proceeds in relation to SPS’ New Mexico retail fuel and purchased power recovery clause. Hearings have been scheduled for April 2006, and a NMPRC decision is expected in late 2006.

5. Commitments and Contingent Liabilities

Environmental Contingencies

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

Ashland Manufactured Gas Plant (MGP) Site — As previously disclosed in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2004, NSP-Wisconsin was named a potentially responsible party for creosote and coal tar contamination at a site in Ashland, Wis. The Ashland site includes property owned by NSP-Wisconsin, which was previously an MGP facility, and two other properties: an adjacent city lakeshore park area, on which an unaffiliated third party previously operated a sawmill, and an area of Lake Superior’s Chequamegon Bay adjoining the park.

On Sept. 5, 2002, the Ashland site was placed on the National Priorities List (NPL). The NPL is intended primarily to guide the United States Environmental Protection Agency (EPA) in determining which sites require further investigation. On Dec. 7, 2004, the EPA approved, with minor contingencies, NSP-Wisconsin’s proposed work plan to complete the remedial investigation and feasibility study. The estimated cost of carrying out the work plan is $1.8 million in 2005. NSP-Wisconsin has recorded a liability of $18.0 million for its potential liability for remediating the Ashland site. Since NSP-Wisconsin cannot currently estimate the cost of remediating the Ashland site, the recorded liability is based upon the minimum of the estimated range of remediation costs, using information available to date and reasonably effective remedial methods. NSP-Wisconsin has deferred, as a regulatory asset, the costs accrued for the Ashland site based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs for other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin biennial retail rate case process. Once approved by the PSCW, deferred MGP remediation costs, less carrying costs, are historically amortized over four or six years. Carrying costs vary directly with the balance in the deferred account and for the period 1995-2002, totaled approximately $800,000.

The Wisconsin Department of Natural Resources (WDNR) and NSP-Wisconsin have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary significantly, between $4 million and $93 million, because different methods of remediation and different results are assumed in each. The EPA and WDNR have not yet selected the method of remediation to use at the site. Until the EPA and the WDNR select a remediation strategy for the entire site and determine NSP-Wisconsin’s level of responsibility, NSP-Wisconsin’s liability for the cost of remediating the Ashland site is not determinable.

In addition to potential liability for remediation and WDNR oversight costs, NSP-Wisconsin may have liability for natural resource damages, including the assessment thereof (collectively NRDA) at the Ashland site. Section 107 of the Comprehensive Environmental Response, Compensation and Liability Act, as amended, provides that a natural resource damages trustee may recover for injury to, destruction or loss of natural resources, including the reasonable costs of assessment, resulting from releases of hazardous substances. Similarly, Section 311 of the Federal Water Pollution Control Act (or Clean Water Act) provides the federal and state governments with the ability to recover costs incurred in the restoration or replacement of natural resources damaged or destroyed as a result of a hazardous substance discharge. In addition to liability for injuries to or loss of services caused by a release from the Ashland site, NSP-Wisconsin could face exposure for additional indirect injuries that could result from the implementation of various remedial technologies during the cleanup phase of the project. NSP-Wisconsin has indicated to the relevant natural resource trustees its intent to pursue a cooperative assessment approach to the NRDA for the Ashland site whereby the question of natural resource damages is assessed and resolved in parallel with the performance of the studies required for selection of a cleanup remedy or remedies. NSP-Wisconsin believes the trustees are interested in discussing such an approach. It is, however, unknown at this time whether a cooperative assessment NRDA approach will be adopted at the Ashland site. Therefore, NSP-Wisconsin is not able to estimate its potential exposure for natural resource damages at the site, but has recorded an estimate of its potential liability based upon the minimum of its estimated range of potential exposure.

Clean Air Interstate and Mercury Rules - In March 2005, the EPA issued two significant new air quality rules. The Clean Air Interstate Rule (CAIR) further regulates sulfur dioxide (SO₂) and nitrogen oxide (NOx) emissions, and the Clean Air Mercury Rule regulates mercury emissions from power plants for the first time.

The objective of the CAIR is to cap emissions of SO₂ and NOx in the eastern United States, including Minnesota, Texas and Wisconsin within Xcel Energy’s service territory. Xcel Energy generating facilities in other states are not affected. When fully implemented, CAIR will reduce SO₂ emissions in 28 eastern states and the District of Columbia by over 70 percent and NOx emissions by over 60 percent from 2003 levels. It is designed to address the transportation of fine particulates, ozone and emission precursors to non-attainment downwind states. CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO₂, with a final compliance deadline in 2015 for both emissions. Under CAIR, each affected state will be allocated an emissions budget for SO₂ and NO_X that will result in significant emission reductions. It will be based on stringent emission controls and forms the basis for a cap-and-trade program. State emission budgets or caps decline over time. States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

On July 11, 2005, SPS, the City of Amarillo and Occidental Permian LTD filed a lawsuit against the EPA and a request for reconsideration with the agency to exclude West Texas from the CAIR. El Paso Electric Co. joined in the request for reconsideration.

Xcel Energy and SPS advocated that West Texas should be excluded from CAIR, because it does not contribute significantly to nonattainment with the fine particulate matter National Ambient Air Quality Standard in any downwind jurisdiction.

• Emissions from plants located in the Texas panhandle are more than 1,000 kilometers away from cities like Chicago, St. Louis and Indianapolis and have no measurable impact on their air quality.

• EPA should not arbitrarily include the entire state of Texas in the rule. As a result of its size, there are significant differences in the air quality impacts of plants in the different regions of Texas.

• EPA has precedent for dividing the state into two regions. As part of the Texas Air Quality strategy, the Texas Commission on Environmental Quality split the state and imposed different requirements on West Texas. The Bush Administration adopted a similar approach in its proposed Clear Skies Act.

• EPA excluded Oklahoma and Kansas from CAIR, but imposes CAIR’s burdens on plants in West Texas. Emissions from West Texas must pass through Oklahoma and Kansas — and over power plants in those states that are not subject to the rule — before reaching the downwind cities the rule is designed to protect.

Under CAIR’s cap and trade structure, SPS can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems. Based on the preliminary analysis of various scenarios of capital investment and allowance purchase, capital investments could range from $30 million to $300 million and allowance purchases or increased operating and maintenance expenses could range from $20 million to $28 million per year, beginning in 2010. This does not include other costs that SPS will have to incur to comply with EPA’s new mercury emission control regulations, which will apply to SPS’ plants.

In addition, Minnesota and Wisconsin will be included in CAIR, and Xcel Energy has generating facilities that will be impacted in these states. Preliminary estimates of capital expenditures associated with compliance with CAIR in Minnesota and Wisconsin range from $30 million to $40 million. Xcel Energy is not challenging CAIR in these states.

These cost estimates represent one potential scenario on how to comply with the CAIR, if West Texas is not excluded from CAIR. There is uncertainty concerning implementation of CAIR. States are required to develop implementation plans within 18 months of the issuance of the new rules and have a significant amount of discretion in the implementation details. Legal challenges to CAIR rules could alter their requirements and/or schedule. The uncertainty associated with the final CAIR rules makes it difficult to project the ultimate amount and timing of capital expenditure and operating expenses.

While Xcel Energy expects to comply with the new rules through a combination of additional capital investments in emission controls at various facilities and purchases of emission allowances, it is continuing to review the alternatives. Xcel Energy believes the cost of any required capital investment or allowance purchases will be recoverable from customers.

The EPA’s Clean Air Mercury Rule also uses a national cap-and-trade system and is designed to achieve a 70 percent reduction in mercury emissions. It affects all coal- and oil-fired generating units across the country greater than 25 megawatts. Compliance with this rule also occurs in two phases, with the first phase beginning in 2010 and the second phase in 2018. States will be allocated mercury allowances based on their baseline heat input relative to other states and by coal type. Each electric generating unit will be allocated mercury allowances based on its percentage of total coal heat input for the state. Xcel Energy is evaluating the impact of the Clean Air Mercury Rule and is currently unable to estimate the cost.

Federal Clean Water Act — The federal Clean Water Act addresses the environmental impacts of cooling water intakes. In July 2004, the EPA published phase II of the rule that applies to existing cooling water intakes at steam-electric power plants. The rule will require Xcel Energy to perform additional environmental studies at 12 power plants in Minnesota, Wisconsin and Colorado to determine the impact the facilities may be having on aquatic organisms vulnerable to injury. 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 plants. 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 plants 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 $33 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.

Leyden Gas Storage Facility - On August 17, 2005, the EPA requested information from PSCo regarding the compliance status of the Leyden facility under the federal Clean Air Act (CAA). On Sept. 19, 2005, PSCo responded to the requests for information. PSCo believes the Leyden facility is in compliance with the CAA and other applicable state and federal environmental laws.

Fort Collins Manufactured Gas Plant (MGP) Site — 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 MGP site and has sold most of the property. An oily substance similar to MGP byproducts was discovered in the Cache la Poudre River. On Nov. 10, 2004, PSCo entered into an agreement with the EPA, the city of Fort Collins and Schrader Oil Co., under which PSCo will perform remediation and monitoring work. PSCo has substantially completed work at the site, with the exception of ongoing maintenance and monitoring. In May 2005, PSCo filed with the CPUC for recovery of the associated costs through its natural gas rate case.

In April 2005, PSCo brought a contribution action against Schrader Oil Co. and related parties alleging Schrader Oil Co. released hazardous substances into the environment and these releases increased the migration and environmental impact of the MGP byproducts at the site. PSCo requested damages, including a portion of the costs PSCo incurred to investigate and remove contaminated sediments from the Cache la Poudre River. On June 27, 2005, Wayne K. Shrader, an owner of Schrader Oil Co., gave notice of his intent to sue PSCo and the City of Fort Collins pursuant to the Resource Conservation and Recovery Act alleging conditions at the Poudre River site “may be causing an imminent and substantial endangerment.” The notice of intent to sue alleges the City’s remedial efforts, as well as the solvents on City property, caused contamination. PSCo believes the allegations with respect to PSCo are without merit and will vigorously defend itself in any suit, which may be filed.

PSCo Notice of Violation - On Nov. 3, 1999, the U.S. Department of Justice filed suit against a number of electric utilities for alleged violations of the federal CAA’s New Source Review (NSR) requirements. The suit is related to alleged modifications of electric generating plants located in the South and Midwest. Subsequently, the EPA also issued requests for information pursuant to the CAA to numerous other electric utilities, including PSCo, seeking to determine whether these utilities engaged in activities that may have been in violation of the NSR requirements. In 2001, PSCo responded to the EPA’s initial information requests. On July 1, 2002, PSCo received a Notice of Violation (NOV) from the EPA alleging violations of the NSR requirements of the CAA at the Comanche and Pawnee plants in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the CAA and NSR process. It believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo also believes that the projects would be expressly authorized under the EPA’s NSR equipment replacement rulemaking promulgated in October 2003. On Dec. 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit stayed this rule while it considers challenges to it. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position. As required by the CAA, the EPA met with Xcel Energy in September 2002 to discuss the NOV.

On March 10, 2005, the Rocky Mountain Environmental Labor Coalition (RMELC) provided notice to PSCo of its intent to sue PSCo for alleged violations of the CAA at the Comanche plant. The notice of intent to sue alleges PSCo has violated the CAA’s Prevention of Significant Deterioration regulations based on allegations that maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. The allegations are the same as those presented in the NOV. On June 9, 2005, Citizens for Clean Air and Water in Pueblo/Southern Colorado (CCAP) and Leslie Glustrom provided notice of intent to sue PSCo for alleged violations of the CAA at the Comanche Plant. The allegations in the notice of intent to sue by CCPA and Ms. Glustrom are substantially identical to those of RMELC. PSCo believes the allegations with respect to PSCo are without merit and will vigorously defend itself in any suit which may be filed.

Cunningham Station Groundwater - Cunningham Station is a natural gas fired power plant constructed in the 1960’s and has 28 water wells installed on its water rights. The well field provides water for boiler makeup, cooling water and potable water. Following an acid release in 2002, groundwater samples revealed elevated concentrations of inorganic salt compounds not related to the release. The contamination was identified in wells located near the plant buildings. The source of contamination is thought to be leakage from ponds that receive blowdown water from the plant. In response to a request by the New Mexico Environment Department (NMED), SPS prepared a corrective action plan to address the groundwater contamination. Under the plan submitted to the NMED, SPS agreed to control leakage from the plant blowdown ponds through construction of a new lined pond, additional irrigation area to minimize percolation, and installation of additional wells to monitor groundwater quality. On June 23, 2005, NMED issued a letter approving the corrective action plan. The action plan is subject to continued compliance with New Mexico regulations and oversight by the NMED. These actions are estimated to cost approximately $3.8 million through 2008.

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.

SchlumbergerSema, Inc. vs. Xcel Energy Inc. (NSP-Minnesota) - Under a 1996 data services agreement, as amended, SchlumbergerSema, Inc. (SLB) provided 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 in May 2000. If NSP-Minnesota cannot establish that basis, the decision would reduce NSP-Minnesota’s damage claim by approximately $5.5 million. In June 2005, the U.S. Bankruptcy Court ruled that NSP-Minnesota is barred from asserting any claim or defense against SLB that is based, in whole or in part, on any pre-May 2000 act or omission, including, but not limited to, any act or omission resulting in design or performance defects, by Cellnet Data Systems Inc., the party with which NSP-Minnesota originally contracted and from which SLB assumed the relevant agreements, which act or omission could have been a basis for NSP to assert a breach of contract against Cellnet Data Systems Inc. This ruling may substantially reduce the amount of recovery of claims by NSP-Minnesota against SLB. In July 2005, SLB requested an evidentiary hearing before the U.S. Bankruptcy Court to determine which claims can proceed in arbitration. The U.S. Bankruptcy Court has not issued a ruling on the request for hearing. Arbitration in the matter is scheduled to begin on Nov. 7, 2005. While the ultimate outcome of NSP-Minnesota’s claims against SLB is not known, any potential recovery would be recorded when received.

Comanche 3 Permit Litigation - On August 4, 2005, CCAP and Clean Energy Action filed suit against the Air Pollution Control Division, Colorado Department of Public Health and Environment and the Air Pollution Control Commission, Colorado Department of Public Health and Environment (Department) in state district court in Pueblo, Colorado. The suit alleges the issuance of environmental permits for the proposed Comanche 3 generating station by the Department violates the Colorado Air Pollution Prevention and Control Act. The plaintiffs have sought judicial review of the issuance of the permits. The plaintiffs have not sought a stay of the permits or an injunction on construction pending judicial review. On Aug. 19, 2005, the Colorado Attorney General, on behalf of the Department, filed an answer in the suit. On the same date, PSCo filed a motion to intervene and an answer in the suit.

Nuclear Waste Disposal Litigation -On June 8, 1998, NSP-Minnesota filed a complaint in the Court of Federal Claims against the DOE requesting damages in excess of $1 billion for the DOE’s partial breach of contract. NSP-Minnesota has demanded damages consisting of the costs of storage of spent nuclear fuel at the Prairie Island and Monticello nuclear generating plants, costs related to the Private Fuel Storage, LLC and costs relating to the 1994 and 2003 state legislation relating to the storage of spent nuclear fuel at Prairie Island. On July 31, 2001, the Court of Federal Claims granted NSP-Minnesota’s motion for partial summary judgment on liability. The Court of Federal Claims has ordered that trial is to commence on October 23, 2006.

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. On Jan. 19, 2005, Xcel Energy filed a motion for summary judgment. On July 26, 2005 the court issued an order granting Xcel Energy’s motion for summary judgment in part with respect to claims for interference with ERISA benefits, breach of contract for non-payment of stock options and unjust enrichment. The court denied Xcel Energy’s motion in part with respect to the allegations of non-payment of deferred compensation benefits.

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, among other reasons, that the lawsuit should be dismissed because it is an attempt to usurp the policy-setting role of the U.S. Congress and the president. On Sept. 19, 2005, the judge granted the defendants’ motion to dismiss on constitutional grounds. Plaintiffs have filed a notice of appeal.

Fru-Con Construction Corporation v. Utility Engineering, et al. — On March 28, 2005, Fru-Con Construction Corporation (Fru-Con) commenced a lawsuit in U.S. District Court for the Eastern District of California against UE and the Sacramento Municipal Utility District (SMUD) for damages allegedly suffered during the construction of a natural gas-fired, combined cycle power plant in Sacramento County. Fru-Con’s complaint alleges that it entered into a contract with SMUD to construct the power plant and further alleges that UE was negligent with regard to the design services it furnished to SMUD. UE denies this claim and intends to vigorously defend itself in this lawsuit. Because this lawsuit was commenced prior to the April 8, 2005 closing of the sale of UE to Zachry Group, Inc., Xcel Energy is obligated to indemnify Zachry up to $17.5 million. Pursuant to the terms of its professional liability policy, UE is insured up to $35 million. On June 1, 2005, UE filed a motion to dismiss Fru-Con’s complaint. A hearing concerning this motion was held on July 18, 2005, with the court taking the matter under advisement. On Aug. 4, 2005, the court granted UE’s motion to dismiss. Because SMUD remains a defendant in this action, the court has not entered a final judgment subject to an appeal with respect to its order to dismiss UE from the lawsuit.

Xcel Energy Inc. Shareholder Litigation —In April 2005, Xcel Energy settled three shareholder-related lawsuits. For a detailed discussion, see the Xcel Energy Quarterly Report on Form 10-Q for the quarter ended March 31, 2005.

Sinclair Oil Corporation vs. e prime inc and Xcel Energy, Inc. - On July 18, 2005, Sinclair Oil Corporation filed a lawsuit against Xcel Energy and its former subsidiary, e prime, in the U.S. District Court for the Northern District of Oklahoma, alleging liability and damages for purported misreporting of price information for natural gas to trade publications in an effort to artificially increase natural gas prices. The complaint also alleges that e prime and Xcel Energy engaged in a conspiracy with other gas sellers to inflate prices through alleged false reporting of gas prices. In response, e prime and Xcel Energy filed a motion with the Multi District Litigation Panel to have this matter transferred to U.S. District Judge Pro in Nevada, who is supervising western area wholesale natural gas marketing litigation, and filed a second motion to dismiss the lawsuit. In response to this motion this matter has been conditionally transferred to Judge Pro.

Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. — On Nov. 19, 2003, a class action complaint filed in the U.S. District Court for the Eastern District of California by Texas-Ohio Energy, Inc. was served on Xcel Energy naming e prime as a defendant. The lawsuit, filed on behalf of a purported class of large wholesale natural gas purchasers, alleges that e prime falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California. The case has been conditionally transferred to Judge Pro. In an order entered April 8, 2005, Judge Pro granted the defendants’ motion to dismiss based on the filed rate doctrine. On May 9, 2005, plaintiffs filed an appeal of this decision to the Ninth Circuit Court of Appeals.

Cornerstone Propane Partners, L.P. et al. vs. e prime inc. et al. — On Feb. 2, 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. On Jan. 25, 2005 plaintiffs filed a motion for class certification, which defendants opposed. On Sept. 30, 2005 the U.S. District Court granted plaintiffs’ motion for class certification. On Oct. 17, 2005, defendants filed a petition with the U.S. Court of Appeals for the Second Circuit challenging the class certification.

Ever-Bloom Inc. vs. Xcel Energy Inc. and e prime et al. - On June 21, 2005, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Ever-Bloom, Inc. The lawsuit names as defendants, among others, Xcel Energy and e prime. The lawsuit, filed on behalf of a purported class of gas purchasers, alleges that defendants falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California purportedly in violation of the Sherman Act. Xcel Energy and e prime intend to vigorously defend themselves against this claim.

Hill, et al., vs. PSCo, et al. — As previously reported, 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. On Jan. 14, 2004, an action against PSCo relating to the fire in Boulder County was filed in Boulder County District Court. There are now 46 plaintiffs, including individuals and insurance companies, and three co-defendants, including PSCo. The plaintiffs asserted damages in excess of $35 million. On or about June 23, 2005, PSCo reached a confidential settlement with all parties, as well as the United States Forest Service and the Denver Public Schools, settling claims in connection with the fire in Boulder County. The financial impact of the settlement is not expected to be material to Xcel Energy.

Other Contingencies

The circumstances set forth in Notes 15, 16 and 17 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2004 and Notes 3, 4 and 6 to the consolidated financial statements in this Quarterly Report on Form 10-Q appropriately represent, in all material respects, the current status of other commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident, and are incorporated herein by reference. The following are unresolved contingencies that are material to Xcel Energy’s financial position:

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

• Guarantees — See Note 6 to the accompanying consolidated financial statements for discussion of exposures under various guarantees.

6. Short-Term Borrowings and Other Financing Instruments

Short-Term Borrowings

In June 2005, Xcel Energy re-entered the commercial paper market. At Sept. 30, 2005, Xcel Energy and its subsidiaries had approximately $308 million of commercial paper outstanding at a weighted average interest rate of 3.81 percent.

Guarantees

Xcel Energy provides various guarantees and bond indemnities supporting certain of its subsidiaries. The guarantees issued by Xcel Energy guarantee payment or performance by its subsidiaries under specified agreements or transactions extending through 2014. As a result, Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees issued by Xcel Energy limit the exposure of Xcel Energy to a maximum amount stated in the guarantees. On Sept. 30, 2005, Xcel Energy had issued guarantees of up to $39.9 million with no known exposure under these guarantees. In addition, Xcel Energy provides indemnity protection for bonds issued by itself and its subsidiaries. The latest expiration for the bond indemnities is 2022. The total amount of bonds with this indemnity outstanding as of Sept. 30, 2005, was approximately $137.1 million. The total exposure of this indemnification cannot be determined at this time. Xcel Energy believes the exposure to be significantly less than the total amount of bonds outstanding.

7. Derivative Valuation and Financial Impacts

Xcel Energy records all derivative instruments on the balance sheet at fair value unless exempted as a normal purchase or sale. Changes in non-exempt derivative instrument’s fair value are recognized currently in earnings unless the derivative has been

designated in a qualifying hedging relationship. The application of hedge accounting allows a derivative instrument’s gains and losses to be reflected in Other Comprehensive Income or to offset related results of the hedged item in the statement of operations, to the extent effective. SFAS No. 133 — “Accounting for Derivative Instruments and Hedging Activities,” as amended, (SFAS No. 133) requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

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, 2005, 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. Currently, the fair value of these hedges is deferred in regulatory assets or liabilities. Amounts deferred in these accounts are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the purchase or sale of energy or energy-related products, the use of natural gas to generate electric energy or gas purchased for resale. As of Sept. 30, 2005, 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.

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. As of Sept. 30, 2005, Xcel Energy had net gains of approximately $1.0 million accumulated in Other Comprehensive Income related to interest rate cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months.

Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily recorded as a component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs, hedging transactions for gas purchased for resale are recorded as a component of gas costs and interest rate hedging transactions are recorded as a component of interest expense. Certain Utility Subsidiaries are allowed to recover in electric or gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. There was no hedge ineffectiveness in the third quarter of 2005.

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)	2005			2004

Accumulated other comprehensive income (loss) related to cash flow hedges at June 30	$	(22.4	)	$		18.1
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges	17.0			(11.2			)
After-tax net realized gains on derivative transactions reclassified into earnings	(5.0		)	(4.6			)
Accumulated other comprehensive income (loss) related to cash flow hedges at Sept. 30	$	(10.4	)	$	2.3

	Nine months ended Sept. 30,
(Millions of Dollars)	2005			2004

Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	0.1		$	8.1
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges	(0.9		)	2.6
After-tax net realized gains on derivative transactions reclassified into earnings	(9.6		)	(8.4		)
Accumulated other comprehensive income (loss) related to cash flow hedges at Sept. 30	$	(10.4	)	$	2.3

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 commodity 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 reported on a net basis within Operating Revenues on the Consolidated Statements of Operations.

Xcel Energy and its subsidiaries also enter into certain commodity-based derivative 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 accordance with SFAS No. 133.

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 the fair value reporting requirements of SFAS No. 133 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that meet these requirements are documented and exempted from the accounting and reporting requirements of SFAS No. 133.

Xcel Energy evaluates all of its contracts within the regulated and nonregulated operations when such contracts are entered to determine if they are derivatives and, if so, if they qualify and meet the normal designation requirements under SFAS No. 133. None of the derivative contracts entered into within the commodity 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).

8. Detail of Interest and Other Income, Net of Nonoperating Expenses

Interest and other income, net of nonoperating expenses, for the three and nine months ended Sept. 30 consists of the following:

	Three months ended Sept. 30,
(Thousands of Dollars)	2005			2004

Interest income	5,587			2,222
Equity income (loss) in unconsolidated affiliates	760			(84		)
Other nonoperating income	1,197			843
Gain on the sale of assets	252			2,509
Minority interest income (loss)	171			(196		)
Interest expense on corporate-owned life insurance, net of increase in cash surrender value	(3,540		)	(4,530		)
Other nonoperating expense	(2,497		)	(1,326		)
Total interest and other income, net of nonoperating expenses	$	1,930		$	(562	)

	Nine months ended Sept. 30,
(Thousands of Dollars)	2005			2004

Interest income	12,226			8,243
Equity income in unconsolidated affiliates	2,073			1,320
Other nonoperating income	5,650			3,030
Gain on the sale of assets	2,232			4,066
Minority interest income (loss)	689			(203		)
Interest expense on corporate-owned life insurance, net of increase in cash surrender value	(13,076		)	(12,873		)
Other nonoperating expense	(5,429		)	(5,420		)
Total interest and other income, net of nonoperating expenses	$	4,365		$	(1,837	)

9. Common Stock and Equivalents

Xcel Energy has common stock equivalents consisting of convertible senior notes and stock options. The dilutive impacts of common stock equivalents affected earnings per share as follows for the three and nine months ending Sept. 30, 2005 and 2004:

	Three months ended Sept. 30, 2005						Three months ended Sept. 30, 2004
(Amounts in thousands, except per share amounts)	Income			Shares	Per-share Amount		Income			Shares	Per-share Amount
Income from continuing operations	$	197,817					$	165,697
Less: Dividend requirements on preferred stock	(1,060		)				(1,060		)
Basic earnings per share:
Income from continuing operations	196,757			402,735	$	0.49	164,637			399,746	$	0.41
Effect of dilutive securities:
$230 million convertible debt	2,895			18,654			3,046			18,654
$57.5 million convertible debt	724			4,663			761			4,663
Stock options	—			33			—			15
Diluted earnings per share:
Income from continuing operations and assumed conversions	$	200,376		426,085	$	0.47	$	168,444		423,078	$	0.40

	Nine months ended Sept. 30, 2005						Nine months ended Sept. 30, 2004
(Amounts in thousands, except per share amounts)	Income			Shares	Per-share Amount		Income			Shares	Per-share Amount
Income from continuing operations	$	400,073					$	400,055
Less: Dividend requirements on preferred stock	(3,180		)				(3,180		)
Basic earnings per share:	396,893
Income from continuing operations				402,028	$	0.99	396,875			399,184	$	0.99
Effect of dilutive securities:
$230 million convertible debt	8,603			18,654			8,895			18,654
$57.5 million convertible debt	2,151			4,663			2,224			4,663
Stock options	—			23			—			16
Diluted earnings per share:
Income from continuing operations and assumed conversions	$	407,647		425,368	$	0.96	$	407,994		422,517	$	0.97

10. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three months ended Sept. 30,
	2005			2004			2005			2004
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	15,115		$	14,143		$	1,671		$	1,525
Interest cost	40,246			41,349			13,765			13,151
Expected return on plan assets	(70,290		)	(75,690		)	(6,425		)	(5,812		)
Amortization of transition (asset) obligation	—			(2		)	3,645			3,644
Amortization of prior service cost (credit)	7,509			7,503			(545		)	(544		)
Amortization of net (gain) loss	1,705			(3,688		)	6,562			5,412
Net periodic benefit cost (credit)	(5,715		)	(16,385		)	18,673			17,376
Settlements and curtailments	—			(223		)	—			—
Credits not recognized due to the effects of regulation	4,842			10,480			—			—
Additional cost recognized due to the effects of regulation	—			—			972			973
Net benefit cost (credit) recognized for financial reporting	$	(873	)	$	(6,128	)	$	19,645		$	18,349

	Nine months ended Sept. 30,
	2005			2004			2005			2004
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits

Service cost	$	45,345		$	43,617		$	5,013		$	4,575
Interest cost	120,738			124,023			41,295			39,453
Expected return on plan assets	(210,048		)	(227,222		)	(19,275		)	(17,438		)
Amortization of transition (asset) obligation	—			(6		)	10,934			10,934
Amortization of prior service cost (credit)	22,527			22,509			(1,634		)	(1,634		)
Amortization of net (gain) loss	5,115			(11,406		)	19,685			16,238
Net periodic benefit cost (credit)	(16,323		)	(48,485		)	56,018			52,128
Settlements and curtailments	—			(926		)	—			—
Credits not recognized due to the effects of regulation	14,526			29,225			—			—
Additional cost recognized due to the effects of regulation	—			—			2,918			2,918
Net benefit cost (credit) recognized for financial reporting	$	(1,797	)	$	(20,186	)	$	58,936		$	55,046

11. Segment Information

Xcel Energy has the following reportable segments: Regulated Electric Utility, Regulated Natural Gas Utility and All Other. Commodity trading operations performed by regulated operating companies are not a reportable segment. Commodity 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, 2005
Operating revenues from external customers	$		2,063,368	$	207,220		$	15,535	$	—		$	2,286,123
Intersegment revenues	61			9,363			—		(9,424		)	—
Total revenues	$		2,063,429	$	216,583		$	15,535	$	(9,424	)	$	2,286,123
Income (loss) from continuing operations	$		189,848	$	(5,640	)	$	11,786	$	1,823		$	197,817
Three months ended Sept. 30, 2004
Operating revenues from external customers	$		1,773,026	$	189,895		$	12,014	$	—		$	1,974,935
Intersegment revenues	304			1,120			—		(1,424		)	—
Total revenues	$		1,773,330	$	191,015		$	12,014	$	(1,424	)	$	1,974,935
Income (loss) from continuing operations	$	170,115		$	(5,821	)	$	11,543	$	(10,140	)	$	165,697

(Thousands of Dollars)	Regulated Electric Utility		Regulated Natural Gas Utility		All Other		Reconciling Eliminations			Consolidated Total
Nine months ended Sept. 30, 2005
Operating revenues from external customers	$	5,318,573	$	1,368,622	$	53,344	$	—		$	6,740,539
Intersegment revenues	371		14,461		—		(14,832		)	—
Total revenues	$	5,318,944	$	1,383,083	$	53,344	$	(14,832	)	$	6,740,539
Income (loss) from continuing operations	$	353,988	$	46,556	$	28,472	$	(28,943	)	$	400,073
Nine months ended Sept. 30, 2004
Operating revenues from external customers	$	4,707,620	$	1,221,253	$	55,035	$	—		$	5,983,908
Intersegment revenues	848		6,781		—		(7,629		)	—
Total revenues	$	4,708,468	$	1,228,034	$	55,035	$	(7,629	)	$	5,983,908
Income (loss) from continuing operations	$	358,984	$	40,226	$	26,120	$	(25,275	)	$	400,055

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;

• 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 Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission and similar entities with regulatory oversight;

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

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

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

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

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

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

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

• Social attitudes regarding the utility and power industries;

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

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

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

• Risks associated with implementations of new technologies;

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

• The other risk factors listed from time to time by Xcel Energy in reports filed with the SEC, including Exhibit 99.01 to this report on Form 10-Q for the quarter ended Sept. 30, 2005.

RESULTS OF OPERATIONS

Summary of Financial Results

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

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

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

Discontinued operations consist of the following:

• the nonregulated subsidiary Quixx Corp., a former subsidiary of UE that partners in cogeneration projects, which was classified as held for sale in the third quarter of 2005 based on a decision to divest this business;

• the nonregulated subsidiary UE for which Xcel Energy reached an agreement to sell in March 2005;

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

• the regulated utility business of CLF&P, which was sold in January 2005; and

• the nonregulated subsidiaries Xcel Energy International and e prime, substantially all of which were divested in 2004.

Prior-year financial statements have been reclassified 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,						Nine months ended Sept. 30,
Contribution to Earnings (Millions of dollars)	2005			2004			2005			2004
GAAP income (loss) by segment
Regulated electric utility segment income — continuing operations	$	189.8		$	170.1		$	354.0		$	359.0
Regulated natural gas utility segment income — continuing operations	(5.6		)	(5.8		)	46.6			40.2
Other utility results (a)	10.0			9.2			22.8			20.9
Utility segment income — continuing operations	194.2			173.5			423.4			420.1

Other nonregulated results and holding company costs (a)	3.6			(7.8		)	(23.3		)	(20.1		)
Income — continuing operations	197.8			165.7			400.1			400.0

Regulated utility income — discontinued operations	—			0.4			0.2			1.9
Other nonregulated income — discontinued operations	(1.8		)	(119.4		)	0.6			(119.0		)
Income — discontinued operations	(1.8		)	(119.0		)	0.8			(117.1		)
Total GAAP income	$	196.0		$	46.7		$	400.9		$	282.9

	Three months ended Sept. 30,						Nine months ended Sept. 30,
	2005			2004			2005			2004
GAAP earnings per share contribution by segment
Regulated electric utility segment — continuing operations	$	0.45		$	0.40		$	0.83		$	0.85
Regulated natural gas utility segment — continuing operations	(0.01		)	(0.01		)	0.11			0.09
Other utility results (a)	0.02			0.02			0.05			0.05
Utility segment earnings per share — continuing operations	0.46			0.41			0.99			0.99

Other nonregulated results and holding company costs (a)	0.01			(0.01		)	(0.03		)	(0.02		)
Earnings per share — continuing operations	0.47			0.40			0.96			0.97

Regulated utility earnings — discontinued operations	—			—			—			—
Other nonregulated earnings — discontinued operations	—			(0.28		)	—			(0.28		)
Earnings per share — discontinued operations	—			(0.28		)	—			(0.28		)
Total GAAP earnings per share - diluted	$	0.47		$	0.12		$	0.96		$	0.69

(a) Not a reportable segment. Included in All Other segment results in Note 11 to the consolidated financial statements. Other utility results, included in the earnings contribution table above, include 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, 2005 earnings per share compared with the same period in 2004, which are discussed in more detail later.

Increase (decrease)	Three months ended Sept. 30, 2005 vs. 2004		Nine months ended Sept. 30, 2005 vs. 2004
2004 Earnings per share — diluted	$	0.12	$	0.69

Components of change — 2005 vs. 2004
Higher base electric utility margins	0.10		0.20
Lower short-term wholesale and commodity trading margins	(0.02)		(0.05)
Higher depreciation and amortization expense	(0.02)		(0.08)
Higher operating and maintenance expense	(0.03)		(0.11)
Effective tax rate changes and other	0.04		0.03
Net change in earnings per share — continuing operations	0.07		(0.01)

Changes in Earnings Per Share — Discontinued Operations	0.28		0.28

2005 Earnings per share — diluted	$	0.47	$	0.96

Utility Segment Results

Earnings for the third quarter of 2005 increased due to higher electric margins resulting from favorable weather in 2005 compared with unfavorable weather in 2004 and sales growth, particularly in the northern regions. Partially offsetting the increase were increased operating and maintenance expense, and higher depreciation expense resulting from major plant and software additions completed in 2004 and early 2005. See below for additional discussion of specific margin and cost items affecting utility operating results.

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

	Earnings per Share Increase (Decrease)
	2005 vs. Normal		2004 vs. Normal			2005 vs. 2004

Three months ended Sept. 30	$	0.04	$	(0.04	)	$	0.08
Nine months ended Sept. 30	$	0.04	$	(0.07	)	$	0.11

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,
	2005			2004			2005			2004

Financing costs and preferred dividends — holding company	$	(0.03	)	$	(0.02	)	$	(0.07	)	$	(0.05	)
Other	0.04			0.01			0.04			0.03
Total other nonregulated and holding company	$	0.01		$	(0.01	)	$	(0.03	)	$	(0.02	)

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 and Holding Company - Nonregulated and holding company segment earnings for the three months ended Sept. 30, 2005 includes additional income tax benefit recorded, in part to eliminate the difference in tax expense computed based on the actual year-to-date effective tax rate at the subsidiary level as compared to the forecasted annual consolidated effective tax rate.

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

(Millions of dollars)	Base Electric Utility			Short-Term Wholesale			Commodity Trading			Consolidated Total
Three months ended Sept. 30, 2005
Electric utility revenue (excluding commodity trading)	$	2,004		$	61		$	—		$	2,065
Electric fuel and purchased power	(1,078		)	(43		)	—			(1,121		)
Commodity trading revenue	—			—			282			282
Commodity trading costs	—			—			(284		)	(284		)
Gross margin before operating expenses	$	926		$	18		$	(2	)	$	942
Margin as a percentage of revenue	46.2		%	29.5		%	(0.7%		)	40.1		%

Three months ended Sept. 30, 2004
Electric utility revenue (excluding commodity trading)	$	1,689		$	76		$	—		$	1,765
Electric fuel and purchased power	(833		)	(56		)	—			(889		)
Commodity trading revenue	—			—			256			256
Commodity trading costs	—			—			(248		)	(248		)
Gross margin before operating expenses	$	856		$	20		$	8		$	884
Margin as a percentage of revenue	50.7		%	26.3		%	3.1		%	43.7		%

Short-term wholesale and commodity trading margins decreased approximately $12 million for the third quarter compared with the same period in 2004. The higher 2004 short-term wholesale results reflect the impact of more favorable market conditions and higher levels of surplus generation available to sell.

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)	2005 vs. 2004

Sales growth (excluding weather impact)	$	15
Estimated impact of weather	62
Fuel and purchased power cost recovery	183
Firm wholesale	16
Quality of Service obligations	(11		)
Transmission revenue	6
Conservation and non-fuel rider revenue	8
Other	36
Total base electric utility revenue increase	$	315

Base Electric Utility Margin

(Millions of dollars)	2005 vs. 2004

Sales growth (excluding weather impact)	$	11
Estimated impact of weather	53
Purchased capacity costs	(10		)
Quality of service obligations	(11		)
Transmission costs	7
Transmission revenue	6
Conservation and non-fuel rider revenue	8
Capacity sales	2
Other	4
Total base electric utility margin increase	$	70

Base electric utility revenues and margins increased largely due to weather-normalized retail electric sales growth of approximately 1.4 percent and favorable weather. Also increasing revenues were higher fuel and purchased power costs, which are largely passed through to customers.

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)	2005			2004

Natural gas utility revenue	$	207		$	190
Cost of natural gas sold and transported	(127		)	(111		)
Natural gas utility margin	$	80		$	79

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)	2005 vs. 2004
Sales growth, excluding weather impacts	1
Estimated impact of weather on firm sales volume	(2		)
Purchased gas adjustment clause recovery	22
Off-system sales	(4		)
Total natural gas revenue increase	$	17

Natural gas revenue increased mainly due to higher natural gas costs in 2005, which are passed through to customers.

Natural Gas Margin

(Millions of dollars)	2005 vs. 2004
Sales growth, excluding weather impacts	1
Estimated impact of weather on firm sales volumes	(2		)
Off-system sales	(4		)
Transportation and other	6
Total natural gas margin increase	$	1

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)	2005			2004

Nonregulated and other revenue	$	16		$	12
Nonregulated cost of goods sold	(4		)	(2		)
Nonregulated margin	$	12		$	10

Non-Fuel Operating Expense and Other Costs

Other Operating and Maintenance Expenses — Utility — Other operating and maintenance expenses for the third quarter of 2005 increased by approximately $22 million, or 5.8 percent, compared with the same period in 2004. The increase is primarily due to higher employee benefit costs of approximately $10 million compared with 2004. The higher employee benefit costs are primarily associated with increased pension expense. In addition, the increase reflects the unfavorable impact of $8.5 million related to two accrued litigation adjustments recorded in 2005 and 2004, as well as $4.8 million related to a favorable inventory adjustment recorded in 2004

Depreciation and Amortization — Depreciation and amortization expense increased by approximately $13 million, or 7.5 percent, for the third quarter of 2005, when compared with the same period in 2004. The change was primarily due to the installation of new steam generators at the Prairie Island nuclear plant and software system additions during 2004 and early 2005, both of which have relatively short depreciable lives compared with other capital additions. In addition, renewable development fund and renewable cost recovery amortizations increased over 2004. The increase was partially offset by the changes in lives and net salvage rates contained in two NSP-Minnesota depreciation filings approved by state regulators during August 2005.

Income taxes — Income taxes for continuing operations decreased by $13 million for the third quarter of 2005 compared with the same period in 2004. The effective tax rate for continuing operations was 23.5 percent for the third quarter of 2005, compared with 30.9 percent for the same period in 2004. Income taxes recorded in the third quarter of 2005 reflect tax benefits from increased research credits and a net operating loss carryback. Income tax expense recorded in the third quarter of 2005 also reflects reductions to adjust to the forecasted annual effective tax rate.

Income Statement Analysis — First Nine Months of 2005 vs. First Nine Months of 2004

Electric Utility, Short-term Wholesale and Commodity Trading Margins

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

(Millions of Dollars)	Base Electric Utility			Short- Term Wholesale			Commodity Trading			Consolidated Total
Nine months ended Sept. 30, 2005
Electric utility revenue (excluding commodity trading)	$	5,162		$	153		$	—		$	5,315
Electric fuel and purchased power	(2,700		)	(95		)	—			(2,795		)
Commodity trading revenue	—			—			513			513
Commodity trading costs	—			—			(509		)	(509		)
Gross margin before operating expenses	$	2,462		$	58		$	4		$	2,524
Margin as a percentage of revenue	47.7		%	37.9		%	0.8		%	43.3		%

Nine months ended Sept. 30, 2004
Electric utility revenue (excluding commodity trading)	$	4,501		$	193		$	—		$	4,694
Electric fuel and purchased power	(2,182		)	(109		)	—			(2,291		)
Commodity trading revenue	—			—			493			493
Commodity trading costs	—			—			(479		)	(479		)
Gross margin before operating expenses	$	2,319		$	84		$	14		$	2,417
Margin as a percentage of revenue	51.5		%	43.5		%	2.8		%	46.6		%

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)	2005 vs. 2004
Fuel and purchased power cost recovery	$	409
Sales growth (excluding weather impact)	45
Firm wholesale	46
Estimated impact of weather	87
Non-fuel rider revenue	15
Capacity sales	10
Purchased capacity cost adjustment	13
Other	36
Total base electric utility revenue increase	$	661

Base Electric Utility Margin

(Millions of dollars)	2005 vs. 2004
Sales growth (excluding weather impact)	$	34
Estimated impact of weather	75
Purchased capacity costs	(18		)
Quality of service obligation	(4		)
Conservation and non-fuel rider revenue	15
Transmission revenue	3
Transmission costs	15
Capacity sales	10
Other	13
Total base electric utility margin increase	$	143

Short-term wholesale and commodity trading margins decreased $36 million for the first nine months of 2005 compared with the same period in 2004. The higher 2004 short-term wholesale results reflect the impact of more favorable market conditions and higher levels of surplus generation available to sell. In addition, a preexisting contract contributed $17 million in the first quarter of 2004 and expired at that time.

Natural Gas Utility Margins

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2005			2004
Natural gas utility revenue	$	1,369		$	1,221
Cost of natural gas sold and transported	(1,028		)	(892		)
Natural gas utility margin	$	341		$	329

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)	2005 vs. 2004
Purchased gas adjustment clause recovery	$	156
Estimated impact of weather on firm sales volume	(8		)
Sales growth (excluding weather impact)	2
Off system sales	(12		)
Transportation	5
Base rate changes in Minnesota	4
Other	1
Total natural gas revenue increase	$	148

Natural Gas Margin

(Millions of dollars)	2005 vs. 2004
Sales growth (excluding weather impact)	$	2
Estimated impact of weather on firm sales volume	(2		)
Off system sales	(4		)
Base rate changes in Minnesota	4
Transportation	3
Other	9
Total natural gas margin increase	$	12

Nonregulated Operating Margins

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

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2005			2004
Nonregulated and other revenue	$	53		$	55
Nonregulated cost of goods sold	(17		)	(20		)
Nonregulated margin	$	36		$	35

Non-Fuel Operating Expense and Other Costs

Other Operating and Maintenance Expenses — Utility — Other operating and maintenance expenses for the first nine months of 2005 increased $76 million, or 6.5 percent, compared with the same period in 2004. Two nuclear plant refueling, inspection and upgrade outages in 2005, with no comparable outages in the first nine months of 2004, increased costs by approximately $33 million. In addition, employee benefit costs were approximately $20 million higher in 2005 than 2004, primarily due to increased performance-based compensation and pension benefits. Also contributing to the increase was the unfavorable impact of $8.5 million related to two accrued litigation adjustments recorded in 2005 and 2004, as well as $4.8 million related to a favorable inventory adjustment in 2004.

Depreciation and Amortization — Depreciation and amortization expense increased by approximately $56 million, or 10.8 percent, for the first nine months of 2005, when compared with the same period in 2004. The change was primarily due to the installation of new steam generators at the Prairie Island nuclear plant and software system additions during 2004 and early 2005, both of which have relatively short depreciable lives compared with other capital additions. In addition, renewable development fund and renewable cost recovery amortization increased over 2004. The increase was partially offset by the changes in lives and net salvage rates contained in two NSP-Minnesota depreciation filings approved by state regulators during August 2005.

Income taxes — Income taxes for continuing operations decreased by $32 million for the first nine months of 2005 compared with the same period in 2004. The effective tax rate for continuing operations was 24.6 percent for the first nine months of 2005, compared with 28.9 percent for the same period in 2004. Income taxes recorded in 2005 reflect tax benefits from increased research credits and a net operating loss carryback.

Factors Affecting Results of Continuing Operations

Fuel Supply and Costs

Coal Deliverability

PSCo and SPS previously notified the DOE of reduced inventories of coal at their electric generating stations. Delivery of coal from the Powder River Basin region in Wyoming has been disrupted by train derailments and other operational problems purportedly caused by deteriorated rail track beds of approximately 100 miles in length in Wyoming. The BNSF Railway Co. (BNSF) and the Union Pacific Railroad (UPRR) jointly own the rail line. The BNSF operates and maintains the rail line. The Powder River Basin is a primary source of coal used by SPS in the operation of its two coal-fired electric generating stations and the primary source used by PSCo in the operation of a number of its coal-fired electric generating stations.

BNSF and UPRR have indicated that repair and reconstruction of the deteriorated sections of rail track beds may take the balance of the year. While BNSF and UPRR have begun to repair the rail beds, they continue to work with Xcel Energy in identifying options in the interim to increase the rate of coal deliveries. Additionally, Xcel Energy analyzed the magnitude, likelihood and effects of reduced coal deliveries to PSCo’s and SPS’ generating stations and developed an interim plan to conserve coal. The interim plan included temporarily modifying the dispatch of their coal-fired electric generating stations to conserve existing coal supplies. Both PSCo and SPS have increased power purchases from third parties and, where practicable, have increased the use of natural gas for electric generation to replace the coal-fired electric generation. Also, the companies contacted wholesale customers to identify options to reduce sales levels, if necessary.

The cost of purchased power and natural gas for electric generation is higher than that for coal-fired electric generation, and the use of these sources to replace coal-fired electric generation increased the price of electricity for retail and wholesale customers.

PSCo and SPS have discussed this situation with the staffs of the regulatory commissions in Colorado, Texas and New Mexico.

In Colorado, PSCo is subject to several retail adjustment clauses that recover fuel, purchased energy and resource costs. The Electric Commodity Adjustment (ECA) is an incentive adjustment mechanism that compares actual fuel and purchased energy expenses in a calendar year to a benchmark formula. The benchmark formula increases with natural gas prices, but not necessarily with increased volumes of natural gas usage due to coal supply disruption. Therefore, any disruption in coal supply could adversely affect fuel cost recovery. However, based on the interim mitigation plans implemented by PSCo, the current fuel costs are below the benchmark, and at Sept. 30, 2005, a positive accrual of $6.5 million has been recorded. The ECA provides for an $11.25 million cap on any cost sharing over or under the allowed ECA formula rate. Any cost in excess of the $11.25 million cap is completely recovered from customers, while any savings in excess of the $11.25 million cap is completely refunded to customers. Subject to the terms of the ECA, PSCo anticipates it would recover any increased fuel and purchased energy costs greater than the cap from its customers.

Because 2005 natural gas prices have been higher than projected when the ECA tariff rates were set in January 2005, PSCo is carrying a deferred ECA balance, including unbilled revenue projected to reach over $54 million by the end of October 2005. On October 5, 2005, PSCo filed an application to adjust the ECA rate for November and December 2005 to reduce the ECA deferred balance and to update its projection of natural gas prices. This application, if granted, is projected to increase 2005 electric revenues by approximately $115.7 million.

In Texas, fuel and purchased energy costs are recovered through a fixed fuel and purchased energy recovery factor, which is part of SPS’ retail electric rates. If it appears that SPS will materially over-recover or under-recover these costs, the factor may be revised upon application by SPS or action by the PUCT. The regulations require surcharging of under-recovered amounts, including interest, when they exceed 4 percent of SPS’ annual fuel and purchased energy costs, as allowed by the PUCT, if the condition is expected to continue. SPS expects to file a fuel surcharge to recover under-recovered costs in November 2005.

In New Mexico, increases and decreases in fuel and purchased energy costs, including deferred amounts, are recovered through a monthly fuel and purchased power clause with a two-month lag. Wholesale customers, under the FERC jurisdiction also pay a monthly fuel cost adjustment calculated on actual fuel and purchased power costs in accordance with the FERC’s fuel clause

regulations.

While SPS believes that it should be allowed to recover these higher costs, the ultimate success of recovery could significantly impact the 2005 financial results of SPS and possibly Xcel Energy.

While operations of NSP- Minnesota and NSP-Wisconsin have not been impacted to the same extent by the reduced deliveries of coal from the Powder River Basin in Wyoming, NSP-Minnesota implemented a mitigation plan to conserve existing coal supplies for the NSP System, which includes NSP-Minnesota and NSP-Wisconsin. This plan includes increased power purchases from third parties and, where practicable, an increased use of natural gas for electric generation to replace the coal-fired electric generation. Production costs for the NSP System increased as a result of implementation of the mitigation plan.

NSP-Minnesota’s retail electric rate schedules in the Minnesota, North Dakota and South Dakota jurisdictions include a fuel clause adjustment (FCA) to billings and revenues for changes in prudently incurred cost of fuel, fuel-related items and purchased energy. NSP-Minnesota is permitted to recover these costs through FCA mechanisms individually approved by the regulators in each jurisdiction. The FCA mechanisms allow NSP-Minnesota to bill customers for the cost of fuel and fuel-related costs used to generate electricity at its plants and energy purchased from other suppliers. In general, capacity costs are not recovered through the FCA. NSP-Minnesota’s electric wholesale customers also have a FCA provision in their contracts. NSP-Minnesota anticipates it will recover increased costs resulting from its mitigation plan through the fuel cost adjustment.

In Wisconsin, NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers. NSP-Wisconsin may seek deferred accounting treatment and future rate recovery of increased costs due to an “emergency” event, if that event causes fuel and purchased power costs to exceed the amount included in rates on an annual basis by more than 2 percent. Coal deliverability has not resulted in an emergency event to date.

Natural Gas Cost

A variety of market factors have contributed to higher natural gas prices and are expected to continue to do so over the course of the coming months. The direct impact of these higher costs is generally mitigated for Xcel Energy through recovery of such costs from customers through various fuel cost recovery mechanisms. However, higher fuel costs could significantly impact the results of operations, if requests for recovery are unsuccessful. In addition, the higher fuel costs could reduce customer demand or increase bad debt expense, which could also have a material impact on Xcel Energy’s results of operations. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases are expected to have an impact on the cash flows of Xcel Energy. Xcel Energy is unable to predict the extent to which the prices will increase or the ultimate impact of such increases on its results of operations or cash flows.

Regulation

For a general discussion of market-based rates, the MISO Day 2 market and the SPS fuel reconciliation case, see Note 4 to the consolidated financial statements.

Environmental Matters

See a discussion of the Clean Air Interstate and Mercury Rules at Note 5 to the consolidated financial statements.

Tax Matters

See a discussion of tax matters associated COLI policies at Note 3 to the consolidated financial statements.

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, 2004, 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, 2004. Commodity price risks for Xcel Energy’s regulated subsidiaries are mitigated in most jurisdictions due to cost-based rate regulation. At Sept. 30, 2005, there were no material changes to the financial market risks that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2004, in Item 7A of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2004. Value-at-risk, commodity trading and hedging information is provided below for informational purposes.

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

Xcel Energy 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 associated with the short-term wholesale and commodity trading operations. The VaR for the commodity trading operations, assuming a three-day holding period for electricity and natural gas, as of Sept. 30, 2005, is as follows:

(Millions of Dollars)	Period Ended Sept. 30, 2005		Change from Period Ended June 30, 2005		VaR Limit		Average		High		Low

Commodity Trading (1)	$	1.44	$	0.34	$	5.0	$	1.42	$	2.90	$	0.92

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

Commodity Trading and Hedging Activities

Xcel Energy and its subsidiaries engage in short-term wholesale and commodity trading activities that are accounted for in accordance with SFAS No. 133. Xcel Energy and its subsidiaries make wholesale purchases and sales of energy and energy-related products and natural gas in order to optimize the value of their electric generating facilities and retail supply contracts. Xcel Energy also engages in limited commodity trading activities. Xcel Energy utilizes various physical and financial contracts and instruments for the purchase and sale of energy, energy-related products, capacity, natural gas, transmission and natural gas transportation.

For the period ended Sept. 30, 2005, these contracts and instruments, with the exception of transmission and natural gas transportation contracts, which meet the definition of a derivative in accordance with SFAS 133, were marked to market. Changes in fair value of commodity 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 commodity trading contracts for the nine months ended Sept. 30, 2005 and 2004 were as follows:

	Nine months ended Sept. 30,
(Millions of Dollars)	2005			2004

Fair value of contracts outstanding at Jan. 1	$	—		$	4.2
Contracts realized or otherwise settled during the period	(6.3		)	(21.9		)
Fair value of trading contract additions and changes during the period	4.2			14.9
Fair value of contracts outstanding at Sept. 30	$	(2.1	)	$	(2.8	)

As of Sept. 30, 2005, the sources of fair value of the commodity trading and hedging net assets were as follows:

Commodity 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	$	1,848		$			$		$	$	1,848
	2	221			1,164			327			1,712
PSCo	1	(7,068		)	591						(6,477		)
	2	1,940			(140		)				1,800
Total Futures/Forwards Fair Value		$	(3,059	)	$	1,615		$	327	$	$	(1,117	)

	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	$	(1,522	)	$	$	$	$	(1,522	)
PSCo	2	559						559
Total Options Fair Value		$	(963	)	$	$	$	$	(963	)

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

NSP-Minnesota	2	$	39,670	$	$	$	$	39,670
PSCo	2	2,687					2,687
Total Futures/Forwards Fair Value		$	42,357	$	$	$	$	42,357

	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	$	58,891	$	85	$	$	$	58,976
NSP-Wisconsin	2	12,746						12,746
PSCo	2	172,272		1,068				173,340
Total Options Fair Value		$	243,909	$	1,153	$	$	$	245,062

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

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

In the above tables, only “hedge” transactions are included for NSP-Minnesota, NSP-Wisconsin and PSCo. “Normal purchases and sales” transactions have been excluded. The fair value adjustments for the PSCo hedging contracts noted above are reflected as components of regulatory assets and liabilities, due to the impact of regulation.

At Sept. 30, 2005, a 10-percent increase in market prices over the next 12 months for trading contracts would decrease pretax income from continuing operations by approximately $2.2 million, whereas a 10-percent decrease would increase pretax income from continuing operations by approximately $2.5 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, 2005, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense by approximately $6.9 million annually, or approximately $1.7 million per quarter. See Note 7 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, 2005, a 10-percent increase in prices would have resulted in a net mark-to-market increase in credit risk exposure of $37.6 million, while a decrease of 10-percent would have resulted in a decrease of $35.2 million.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

	Nine months ended Sept. 30,
(Millions of Dollars)	2005		2004

Cash provided by (used in) operating activities
Continuing operations	$	1,152	$	958
Discontinued operations	158		(327		)
Total	$	1,310	$	631

Cash provided by operating activities for continuing operations increased by $194 million for the first nine months of 2005, compared with the first nine months of 2004. The increase was primarily due to an increase in electric margin related to sales growth and more favorable weather. Cash used in operating activities for discontinued operations decreased by $485 million in the first nine months of 2005 due to the sale of CLF&P and NRG settlement payments made in the first quarter of 2004, offset by tax benefits received in the same period.

	Nine months ended Sept. 30,
(Millions of Dollars)	2005			2004

Cash provided by (used in) investing activities
Continuing operations	$	(940	)	$	(838	)
Discontinued operations	72			11
Total	$	(868	)	$	(827	)

Cash used in investing activities for continuing operations increased by $102 million for the first nine months of 2005, compared with the first nine months of 2004. This is largely due to increased capital expenditures in 2005 and changes in restricted cash requirements, partially offset by the proceeds from the sale of an office building. Cash provided by investing activities for discontinued operations increased $61 million in 2005 compared with 2004. The increase was primarily due to the receipt of proceeds from the sale of CLF&P in 2005.

	Nine months ended Sept. 30,
(Millions of Dollars)	2005			2004

Cash used in financing activities
Continuing operations	$	(277	)	$	(262	)
Discontinued operations	—			—
Total	$	(277	)	$	(262	)

Cash used in financing activities for continuing operations increased by approximately $15 million for the first nine months of 2005, compared with the first nine months of 2004. The increase was primarily due to the excess of repayments of credit facility borrowings and long-term debt of proceeds received from the issuance of long-term debt, as well as higher dividends paid in 2005. These decreases were offset by stock repurchases in 2004.

Credit Facilities and Other Sources of Liquidity

Xcel Energy and Utility Subsidiary Credit Facilities - As of Oct. 20, 2005, Xcel Energy had the following credit facilities available to meet its liquidity needs:

(Millions of Dollars) Company	Facility			Drawn*		Available			Cash		Liquidity			Maturity

NSP-Minnesota	$		375	$	10	$	365		$	30	$		395	April 2010
PSCo	$		500	$	5	$	495		$	87	$		582	April 2010
SPS	$		250	$	—	$	250		$	4	$		254	April 2010
Xcel Energy — Holding Company	$		600	$	340	$	260		$	3	$		263	Nov. 2009
Total	$	1,725		$	355	$		1,370	$	124	$	1,494

* Includes short-term borrowings, outstanding commercial paper and letters of credit

The liquidity table reflects the payment of common dividends on Oct. 20, 2005.

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. On August 15, 2005, NSP-Wisconsin filed with the PSCW to increase the limit on short-term debt from $50 million to $75 million. Currently, NSP-Wisconsin borrows on a short-term basis through an inter-company borrowing agreement with NSP-Minnesota. At Sept. 30, 2005, NSP-Wisconsin had $23.8 million of short-term borrowings outstanding and an insignificant amount of cash.

Xcel Energy has renewed the credit facilities of its operating utility companies. NSP-Minnesota, PSCo and SPS each have individual 5-year, unsecured credit facilities. The combined size of the facilities is $1.125 billion, with NSP-Minnesota comprising $375 million, PSCo comprising $500 million and SPS comprising $250 million. Each credit facility has one financial covenant requiring that the

debt to total capitalization ratio of each entity be less than or equal to 65 percent. The facilities closed on April 21, 2005.

To provide additional liquidity in the current natural gas price environment, Xcel Energy has requested its existing bank group provide increases in the size of three revolving credit facilities under the optional increase features in each of the credit agreements. The request includes a $100 million increase in Xcel Energy’s 5-year revolving credit facility from its current size of $600 million to $700 million; a $100 million increase in PSCo’s 5-year revolving credit facility from its current size of $500 million to $600 million; and a $75 million increase in NSP-Minnesota’s 5-year revolving credit facility from its current size of $375 million to $450 million. Xcel has requested commitments from the bank group by October 25, 2005.

Commercial Paper — On June 10, 2005, Xcel Energy re-entered the commercial paper market by issuing $175 million of notes. Net proceeds were used to repay higher-cost borrowings under its five-year bank credit facility. Xcel Energy’s commercial paper is rated A-2 by Standard & Poor’s Ratings Services and Prime-2 by Moody’s Investor Services, Inc. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by a rating agency. At Sept. 30, 2005, Xcel Energy had $308 million of outstanding commercial paper at a weighted average interest rate of 3.81 percent.

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. NSP-Minnesota, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions. The borrowings or loans outstanding at Sept. 30, 2005, and the SEC approved short-term borrowing limits from the money pool were as follows:

(Millions of Dollars)	Borrowings (Loans)		Total Borrowing Limits
NSP— Minnesota	$	—	$	250
PSCo	$	—	$	250
SPS	$	13.6	$	100

Registration Statements — On March 22, 2005, NSP-Minnesota filed a shelf registration statement with the SEC to register an additional $1 billion of secured or unsecured debt securities, which may be issued from time to time in the future. This registration became effective on April 7, 2005 and supplements the $40 million of debt securities previously registered with the SEC. After issuance of $250 million of first mortgage bonds in July 2005, as discussed below, $790 million remains available under the currently effective registration statements. Short-term debt and financial instruments are discussed in Note 6 to the consolidated financial statements.

SEC Financing Order — On June 20, 2005, Xcel Energy received SEC authorization for long-term and short-term financing and other transactions through June 30, 2008. This order replaces the prior financing authorization, which expired on June 30, 2005. Xcel Energy believes that it has sufficient financing authority to meet its capital needs through June 30, 2008 and that the Energy Policy Act of 2005 will not have an adverse impact on its ability to obtain such financing.

Xcel Energy Credit Facility Amendment — On June 20, 2005 Xcel Energy completed an amendment to its credit agreement dated November 4, 2004. This amendment provides for less restrictive borrowing conditions by eliminating the material adverse change and material litigation representations from ongoing conditions to borrowing. This amendment provides consistency with the operating company credit agreements, which were renewed in April 2005.

Long-term debt — On July 21, 2005, NSP-Minnesota issued $250 million of 5.25 percent first mortgage bonds due July 2035. NSP-Minnesota added the net proceeds from the sale of the first mortgage bonds to its general funds and initially used the proceeds for general corporate purposes, which included the repayment of borrowings under its credit agreement incurred in connection with utility construction and operations. NSP-Minnesota intends to apply a portion of those net proceeds to the repayment at maturity of $70,000,000 aggregate principal amount of 6.125 percent first mortgage bonds, series due Dec. 1, 2005; $2,330,000 aggregate principal amount of the Ramsey County, Minnesota and the County of Washington, Minnesota 4.0 percent Resource Recovery Refunding Revenue Bonds, Collateralized Series 1999 secured by a series of first mortgage bonds, due Dec. 1, 2005; and $2,300,000 aggregate principal amount of the County of Anoka, Minnesota 4.4 percent Resource Recovery Refunding Revenue Bonds, Series 1999 secured by a series of first mortgage bonds, each of which has a scheduled maturity of Dec. 1, 2005.

On August 18, 2005, PSCo issued $129.5 million of 4.375 percent pollution control refunding revenue bonds due September 2017. The proceeds were used to repay prior to maturity $79.5 million of outstanding Adams County Pollution Control Refunding Revenue Bonds, 1993 Series A and $50 million of Morgan County Pollution Control Refunding Revenue Bonds, 1993 Series A.

Effective Oct. 14, 2005, PSCo discharged in accordance with its terms its Indenture, dated as of December 1, 1939, as supplemented, (1939 Indenture). As a result, PSCo’s Indenture, dated as of Oct. 1, 1993, as supplemented, (1993 Indenture) becomes the first lien on PSCo’s electric properties subject to certain permitted liens as provided in the 1993 Indenture. PSCo’s outstanding first collateral trust bonds issued under the 1993 Indenture will, in accordance with their terms, no longer be secured by bonds issued under the 1939 Indenture and will become first mortgage bonds entitled to the benefit of the lien on PSCo’s electric properties under the 1993 Indenture and will be renamed “first mortgage bonds” to reflect this status.

Capital Expenditures

The following is the consolidated Xcel Energy capital expenditure forecast:

Project Description	2005			2006			2007			2008			2009
(Millions of Dollars)
MERP*	$		211	$	336		$	228		$	180		$	44
Comanche 3	62			198			331			284			73
Capital expenditures — base	982			1,035			1,016			920			1,031
Total	$	1,255		$		1,569	$		1,575	$		1,384	$	1,148

*Minnesota emissions reduction project

The following is an update of the capital expenditure forecast for each of the utility subsidiaries of Xcel Energy:

Utility Subsidiary	2005			2006			2007			2008			2009
(Millions of Dollars)
NSP-Minnesota	$		673	$	879		$	697		$	564		$	517
NSP-Wisconsin	58			66			67			95			63
PSCo	414			525			684			604			457
SPS	110			99			127			121			111
Total	$	1,255		$		1,569	$		1,575	$		1,384	$		1,148

The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy’s long-term energy needs. In addition, Xcel Energy’s ongoing evaluation of compliance with future requirements to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.

Earnings Guidance

2005 Earnings Guidance — Xcel Energy’s 2005 earnings per share from continuing operations guidance and key assumptions are detailed in the following table. However, Xcel Energy currently expects that the year’s earnings will be within the lower half of the guidance range.

		2005 Diluted EPS Range
Utility operations		$1.18 - $1.28
COLI tax benefit		$0.09
Holding company financing costs and other		($0.09)
Xcel Energy Continuing Operations — EPS		$1.18 - $1.28

Key Assumptions for 2005:

• Seren is held for sale and accounted for as discontinued operations;

• Normal weather patterns are experienced for the fourth quarter;

• Weather-adjusted retail electric utility sales growth of approximately 1.3 percent to 1.6 percent;

• No weather-adjusted retail natural gas utility sales growth;

• Capacity costs increase by $10 million, net of capacity cost recovery;

• No additional margin impact results from the fuel allocation issue at SPS;

• Short-term wholesale and commodity trading margins decline by approximately $40 million to $50 million;

• Other utility operating and maintenance expense increases approximately 5 percent from 2004;

• Depreciation expense increases approximately 8 percent to 9 percent from 2004;

• Interest expense increases approximately $10 million to $15 million from 2004;

• Allowance for funds used during construction is expected to decline from 2004;

• Xcel Energy continues to recognize corporate-owned life insurance tax benefits of 9 cents per share;

• The effective tax rate for continuing operations is approximately 25 percent to 27 percent; and

• Average common stock and equivalents total approximately 426 million shares, based on the “If Converted” method for convertible notes.

2006 Earnings Guidance — Xcel Energy’s 2006 earnings per share from continuing operations guidance and key assumptions are detailed in the following table.

		2006 Diluted EPS Range
Utility operations		$1.25 - $1.35
COLI tax benefit		$0.10
Holding company financing costs and other		($0.10)
Xcel Energy Continuing Operations — EPS		$1.25 - $1.35

Key Assumptions for 2006:

• Normal weather patterns are experienced;

• Reasonable rate recovery in the following rate increase requests:

o Minnesota electric

o Wisconsin natural gas and electric

o Colorado natural gas

o North Dakota electric;

• Weather-adjusted retail electric utility sales growth of approximately 1.3 percent to 1.7 percent;

• Weather-adjusted retail natural gas utility sales growth of approximately 0.0 percent to 1.0 percent;

• Short-term wholesale and trading margins decline by approximately $15 million to $30 million from projected 2005 levels;

• Other utility operating and maintenance expense increases between 3 percent and 4 percent from projected 2005 levels;

• Depreciation expense increases approximately $100 million to $110 million from projected 2005 levels, approximately $60 million of this increase in depreciation expense relates to changes in decommissioning accruals that are expected to be recovered through rates approved in the Minnesota electric rate case anticipated to be filed in November 2005;

• Interest expense increases approximately $10 million to $15 million from projected 2005 levels;

• Allowance for funds used during construction recorded for equity financing is expected to increase approximately $10 million to $15 million from projected 2005 levels;

• Xcel Energy continues to recognize COLI tax benefits;

• The effective tax rate for continuing operations is approximately 27 percent to 29 percent and

• Average common stock and equivalents total approximately 428 million shares, based on the “If Converted” method for convertible notes.

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 Securities and Exchange Commission rules and forms. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the chief executive officer (CEO) and chief financial officer (CFO), of the effectiveness of our disclosure controls and procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures are effective.

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 certain changes in its internal control over financial reporting during the most recent fiscal quarter in order to make the control environment more effective and efficient.

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 and 5 of the consolidated financial statements in this Quarterly Report on 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, 2004 and Note 16 of the consolidated financial statements in such Form 10-K for a description of certain legal proceedings presently pending. Except as discussed in Notes 4 and 5 herein, 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.

1.01*		Underwriting Agreement dated July 14, 2005 between NSP-Minnesota, Barclays Capital Inc. and J.P. Morgan Securities Inc., as representatives of the Underwriters named therein, relating to $250,000,000 principal amount of 5.25 percent First Mortgage Bonds, Series due July 15, 2035 (Exhibit 1.01 to NSP-Minnesota Current Report on Form 8-K, dated July 14, 2005, file number 000-31387).
4.01*		Amendment to the Credit Agreement dated Nov. 4, 2004 between Xcel Energy and various lenders. (Exhibit 4.01 to Xcel Energy Quarterly Report on Form 10-Q for the second quarter of 2005, file number 001-03034)
4.02*		Supplemental Indenture dated July 1, 2005 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $250,000,000 principal amount of 5.25 percent First Mortgage Bonds, Series due July 15, 2035 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, dated July 14, 2005, file number 000-31387).
4.03*		Supplemental Indenture No. 16, dated as of August 1, 2005, of Public Service Company of Colorado to U.S. Bank Trust National Association, as Trustee. Supplemental to the Indenture dated as of October 1, 1993, establishing the securities of Series No. 16 designated First Collateral Trust Bonds, Series No. 16 (MBIA Collateral Bonds). (Exhibit 4.02 to PSCo Current Report on Form 8-K, dated August 18, 2005, file number 001-03280.)
4.04*		Supplemental Indenture, dated as of August 1, 2005, of Public Service Company of Colorado to U.S. Bank Trust National Association, as Trustee, creating an issue of First Mortgage Bonds, Collateral Series P. Supplemental to Indenture dated as of December 1, 1939, as amended. (Exhibit 4.03 to PSCo Current Report on Form 8-K, dated August 18, 2005, file number 001-03280.)
4.05*		Financing Agreement between Adams County, Colorado and PSCo, dated as of Aug. 1, 2005, relating to $129,500,000 Adams County, Colorado Pollution Control Refunding Revenue Bonds, 2005 Series A. (Exhibit 4.01 to PSCo Current Report on Form 8-K, dated Aug. 18, 2005, file number 001-3280)
10.01		Compensation Practices for Xcel Energy Non-Employee Directors
31.01		Principal Executive Officer’s and Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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.

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

For the quarterly period ended Sept. 30, 2005
or

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

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

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

Class		Outstanding at October 20, 2005
Common Stock, $2.50 par value		402,887,856 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
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
Certifications Pursuant to Section 302
Certifications Pursuant to Section 906
Statement Pursuant to Private Litigation

		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

October 28, 2005