Xcel Energy 10Q 2005 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2005

or

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

For the transition period from to

Commission File Number: 1-3034

Xcel Energy Inc.

(Exact name of registrant as specified in its charter)

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

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

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

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

ý Yes o No

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

Class		Outstanding at July 26, 2005
Common Stock, $2.50 par value		402,746,373 shares

TABLE OF CONTENTS

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 4. Submission of Matters to a Vote of Security Holders
	Item 6. Exhibits
SIGNATURES
Certifications Pursuant to Section 302
Certifications Pursuant to Section 906
Statement Pursuant to Private Litigation

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 June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Operating revenues:
Electric utility	$	1,720,431		$	1,468,340		$	3,255,378		$	2,934,594
Natural gas utility	326,347			271,634			1,161,402			1,031,358
Nonregulated and other	20,239			23,125			43,794			48,365
Total operating revenues	2,067,017			1,763,099			4,460,574			4,014,317

Operating expenses:
Electric fuel and purchased power – utility	912,400			723,021			1,673,809			1,401,714
Cost of natural gas sold and transported – utility	232,039			186,341			900,824			780,593
Cost of sales – nonregulated and other	7,420			10,209			18,104			22,242
Other operating and maintenance expenses – utility	437,639			392,890			840,109			786,535
Other operating and maintenance expenses – nonregulated	9,568			6,287			17,656			13,709
Depreciation and amortization	194,076			173,637			385,865			343,204
Taxes (other than income taxes)	71,370			71,935			147,177			146,303
Total operating expenses	1,864,512			1,564,320			3,983,544			3,494,300
Operating income	202,505			198,779			477,030			520,017

Interest and other income – net of nonoperating expense (see Note 8)	5,066			(296		)	5,557			(717		)
Allowance for funds used during construction - equity	5,450			8,228			10,633			16,684

Interest charges and financing costs:
Interest charges – includes other financing costs of $6,418, $7,003, $12,897 and $14,432, respectively	114,375			110,403			228,017			224,234
Allowance for funds used during construction - debt	(4,534		)	(5,149		)	(9,368		)	(11,252		)
Total interest charges and financing costs	109,841			105,254			218,649			212,982
Income from continuing operations before income taxes	103,180			101,457			274,571			323,002
Income taxes	24,770			15,943			70,279			88,356
Income from continuing operations	78,410			85,514			204,292			234,646
Income from discontinued operations – net of tax (see Note 2)	4,996			792			592			1,571
Net income	83,406			86,306			204,884			236,217
Dividend requirements on preferred stock	1,060			1,060			2,120			2,120
Earnings available to common shareholders	$	82,346		$	85,246		$	202,764		$	234,097

Weighted average common shares outstanding (thousands):
Basic	402,214			399,217			401,668			398,900
Diluted	425,552			422,545			425,004			422,233
Earnings per share – basic: Income from continuing operations	$	0.19		$	0.21		$	0.50		$	0.59
Discontinued operations	0.01			0.00			0.00			0.00
Earnings per share – basic	$	0.20		$	0.21		$	0.50		$	0.59
Earnings per share – diluted:
Income from continuing operations	$	0.19		$	0.21		$	0.49		$	0.57
Discontinued operations	0.01			0.00			0.00			0.00
Earnings per share – diluted	$	0.20		$	0.21		$	0.49		$	0.57

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(Thousands of Dollars)

	Six Months Ended June 30,
	2005			2004

Operating activities:
Net income	$	204,884		$	236,217
Remove income from discontinued operations	(592		)	(1,571		)
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	395,915			356,614
Nuclear fuel amortization	19,673			22,948
Deferred income taxes	28,650			54,431
Amortization of investment tax credits	(5,809		)	(6,111		)
Allowance for equity funds used during construction	(10,633		)	(16,684		)
Undistributed equity in earnings of unconsolidated affiliates	(414		)	104
Write down of assets	3,258			—
Unrealized (gain) loss on derivative financial instruments	1,614			(6,310		)
Change in accounts receivable	(10,745		)	29,641
Change in inventories	107,760			55,097
Change in other current assets	45,864			30,426
Change in accounts payable	(136,199		)	(37,261		)
Change in other current liabilities	(34,166		)	(63,712		)
Change in other noncurrent assets	8,481			(105		)
Change in other noncurrent liabilities	76,920			59,951
Operating cash flows provided by (used in) discontinued operations	101,658			(377,851		)
Net cash provided by operating activities	796,119			335,824

Investing activities:
Utility capital/construction expenditures	(628,623		)	(512,537		)
Allowance for equity funds used during construction	10,633			16,684
Investments in external decommissioning fund	(40,291		)	(40,289		)
Nonregulated capital expenditures and asset acquisitions	(4,486		)	—
Restricted cash	1,621			37,609
Other investments — net	6,392			(7,915		)
Investing cash flows provided by discontinued operations	83,357			4,520
Net cash used in investing activities	(571,397		)	(501,928		)

Financing activities
Short-term borrowings –net	(17,300		)	64,977
Proceeds from issuance of long-term debt	120,888			—
Repayment of long-term debt, including reacquisition premiums	(124,963		)	(146,106		)
Proceeds from issuance of common stock	3,778			—
Repurchase of common stock	—			(32,023		)
Dividends paid	(167,845		)	(151,860		)
Financing cash flows used in discontinued operations	(200		)	(200		)
Net cash used in financing activities	(185,642		)	(265,212		)

Net (decrease) increase in cash and cash equivalents	39,080			(431,316		)
Net decrease in cash and cash equivalents -discontinued operations	(10,015		)	(26,539		)
Net increase in cash and cash equivalents –adoption of FIN No. 46	—			2,644
Cash and cash equivalents at beginning of year	25,403			564,213
Cash and cash equivalents at end of quarter	$	54,468		$	109,002

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

	June 30, 2005			Dec. 31, 2004
ASSETS
Current assets:
Cash and cash equivalents	$	54,468		$	25,403
Accounts receivable – net of allowance for bad debts of $36,981 and $34,694, respectively	774,336			763,591
Accrued unbilled revenues	454,784			435,431
Materials and supplies inventories – at average cost	158,748			161,323
Fuel inventory – at average cost	58,930			64,265
Natural gas inventories - at average cost	115,114			214,964
Recoverable purchased natural gas and electric energy costs	173,480			264,628
Derivative instruments valuation – at market	333,771			129,218
Prepayments and other	141,920			149,687
Current assets held for sale and related to discontinued operations	211,997			362,730
Total current assets	2,477,548			2,571,240
Property, plant and equipment, at cost:
Electric utility plant	18,662,277			18,236,957
Natural gas utility plant	2,678,884			2,617,552
Common utility and other	1,629,983			1,483,589
Construction work in progress	602,094			721,335
Total property, plant and equipment	23,573,238			23,059,433
Less accumulated depreciation	(9,327,199		)	(9,053,834		)
Nuclear fuel – net of accumulated amortization: $1,164,817 and $1,145,228, respectively	97,561			74,308
Net property, plant and equipment	14,343,600			14,079,907
Other assets:
Investments in unconsolidated affiliates	69,411			79,386
Nuclear decommissioning fund and other investments	1,034,030			969,647
Regulatory assets	954,531			850,636
Derivative instruments valuation – at market	348,801			424,786
Prepaid pension asset	664,323			642,873
Other	165,364			177,555
Noncurrent assets held for sale and related discontinued operations	415,919			508,813
Total other assets	3,652,379			3,653,696
Total assets	$	20,473,527		$	20,304,843

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	340,532		$	223,655
Short-term debt	295,000			312,300
Accounts payable	768,710			904,909
Taxes accrued	170,479			209,910
Dividends payable	87,568			83,405
Derivative instruments valuation – at market	102,287			135,098
Other	329,411			350,451
Current liabilities held for sale and related to discontinued operations	94,157			116,266
Total current liabilities	2,188,144			2,335,994
Deferred credits and other liabilities:
Deferred income taxes	2,090,444			2,074,942
Deferred investment tax credits	137,214			143,028
Regulatory liabilities	1,775,172			1,630,545
Derivative instruments valuation – at market	620,508			450,883
Asset retirement obligations	1,125,974			1,091,089
Customer advances	305,913			303,928
Minimum pension liability	63,967			62,669
Benefit obligations and other	400,231			328,521
Noncurrent liabilities held for sale and related to discontinued operations	31,796			79,106
Total deferred credits and other liabilities	6,551,219			6,164,711
Minority interest in subsidiaries	4,662			3,220
Commitments and contingent liabilities (see Note 5)
Capitalization:
Long-term debt	6,116,132			6,353,020
5-year, senior unsecured credit facilities, weighted average interest rate of 4.03% at June 30, 2005	261,000			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 – 402,357,588; 2004 – 400,461,804	5,247,390			5,202,918
Total liabilities and equity	$	20,473,527		$	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
	Number of Shares	Par Value		Capital in Excess of Par Value		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Three months ended June 30, 2004 and 2005
Balance at March 31, 2004	398,882	$	997,204	$	3,887,900	$	442,514		$	(90,121	)	$	5,237,497
Net income						86,306						86,306
Currency translation adjustments									(6,575		)	(6,575		)
After-tax unrealized and realized gains related to derivatives -net (see Note 7)									15,529			15,529
Unrealized loss on marketable securities									(31		)	(31		)
Comprehensive income for the period												95,229
Dividends declared: Cumulative preferred stock of Xcel Energy						(1,060		)				(1,060		)
Common stock						(82,665		)				(82,665		)
Issuances of common stock – net proceeds	513	1,284		7,413								8,697
Balance at June 30, 2004	399,395	$	998,488	$	3,895,313	$	445,095		$	(81,198	)	$	5,257,698

Balance at March 31, 2005	401,835	$	1,004,588	$	3,932,549	$	433,679		$	(103,909	)	$	5,266,907
Net income						83,406						83,406
Minimum pension liability									—			—
After-tax unrealized and realized losses related to derivatives - net (see Note 7)									(24,290		)	(24,290		)
Unrealized loss on marketable securities									(32		)	(32		)
Comprehensive income for the period												59,084
Dividends declared: Cumulative preferred stock of Xcel Energy						(1,060		)				(1,060		)
Common stock						(86,507		)				(86,507		)
Issuances of common stock – net proceeds	523	1,306		7,660								8,966
Balance at June 30, 2005	402,358	$	1,005,894	$	3,940,209	$	429,518		$	(128,231	)	$	5,247,390

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
Six months ended June 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										236,217						236,217
Currency translation adjustments													(1,120		)	(1,120		)
After-tax unrealized and realized gains related to derivatives -net (see Note 7)													9,966			9,966
Unrealized gain on marketable securities													92			92
Comprehensive income for the period																245,155
Dividends declared: Cumulative preferred stock of Xcel Energy										(2,120		)				(2,120		)
Common stock										(157,665		)				(157,665		)
Issuances of common stock - net proceeds		2,230		5,576			32,335									37,911
Purchase for restricted stock issuance		(1,800	)	(4,500		)	(27,523		)							(32,023		)
Balance at June 30, 2004		399,395		$	998,488		$	3,895,313		$	445,095		$	(81,198	)	$	5,257,698

Balance at Dec. 31, 2004		400,462		$	1,001,155		$	3,911,056		$	396,641		$	(105,934	)	$	5,202,918
Net income										204,884						204,884
Minimum pension liability													220			220
After-tax unrealized and realized losses related to derivatives - net (see Note 7)													(22,512		)	(22,512		)
Unrealized loss on marketable securities													(5		)	(5		)
Comprehensive income for the period																182,587
Dividends declared: Cumulative preferred stock of Xcel Energy										(2,120		)				(2,120		)
Common stock										(169,887		)				(169,887		)
Issuances of common stock - net proceeds		1,896		4,739			29,153									33,892
Balance at June 30, 2005	��	402,358		$	1,005,894		$	3,940,209		$	429,518		$	(128,231	)	$	5,247,390

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 June 30, 2005, and Dec. 31, 2004; the results of its operations and changes in stockholders’ equity for the three and six months ended June 30, 2005 and 2004; and its cash flows for the six months ended June 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. 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 discussed below. Results of operations as well as assets and liabilities for the divested businesses and the businesses held for sale are reported on a net basis as a component of discontinued operations for all periods presented. Amounts previously reported for 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 January 21, 2005.

Nonregulated Subsidiaries — All Other Segment

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

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 agreement to sell Seren’s California assets to WaveDivision Holdings, LLC. In July 2005, Xcel Energy reached an agreement to sell Seren’s Minnesota assets to Charter Communications. The sale of Seren in its entirety is expected to be completed in the second half of 2005. 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 — In 2004, Xcel Energy exited all business conducted by its nonregulated subsidiary, e prime, inc., and most conducted by Xcel Energy International Inc.. Xcel Energy sold all of the contractual assets of e prime and closed on the sale of one of the Argentina subsidiaries of Xcel Energy International during the first quarter of 2004. The sale price was immaterial and approximated the book value of Xcel Energy’s investment.

Summarized Financial Results of Discontinued Operations

(Thousands of dollars)	Utility Segments		All Other			Total

Three months ended June 30, 2005
Operating revenue	$	—	$	4,417		$	4,417
Operating and other expenses	—		(3,784		)	(3,784		)
Pretax income (loss) from operations of discontinued components	—		8,201			8,201
Income tax expense (benefit)	—		3,205			3,205
Net income (loss) from discontinued operations	$	—	$	4,996		$	4,996

Three months ended June 30, 2004
Operating revenue and equity in project income	$	26,145	$	41,539		$	67,684
Operating and other expenses	25,216		45,814			71,030
Other income (loss)	—		(1,479		)	(1,479		)
Pretax income (loss) from operations of discontinued components	929		(5,754		)	(4,825		)
Income tax expense (benefit)	283		(5,900		)	(5,617		)
Net income (loss) from operations of discontinued components	$	646	$	146		$	792

(Thousands of dollars)	Utility Segments		All Other			Total

Six months ended June 30, 2005
Operating revenue	$	6,579	$	26,080		$	32,659
Operating and other expenses	6,131		25,028			31,159
Pretax income (loss) from operations of discontinued components	448		1,052			1,500
Income tax expense (benefit)	268		640			908
Net income (loss) from discontinued operations	$	180	$	412		$	592

Six months ended June 30, 2004
Operating revenue and equity in project income	$	45,244	$	109,113		$	154,357
Operating and other expenses	43,082		117,019			160,101
Other income (loss)	—		(652		)	(652		)
Pretax income (loss) from operations of discontinued components	2,162		(8,558		)	(6,396		)
Income tax expense (benefit)	727		(8,694		)	(7,967		)
Net income (loss) from operations of discontinued components	$	1,435	$	136		$	1,571

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

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

Cash	$	16,813	$	31,187
Restricted cash	—		15,000
Trade receivables — net	3,179		22,036
Deferred income tax benefits	180,103		234,305
Other current assets	11,902		60,202
Current assets held for sale	211,997		362,730
Property, plant and equipment — net	45,389		151,590
Deferred income tax benefits	347,146		338,863
Other noncurrent assets	11,079		18,360
Noncurrent assets held for sale	403,614		508,813
Current portion of long-term debt	—		—
Accounts payable — trade	19,740		28,151
Other current liabilities	69,787		88,115
Current liabilities held for sale	89,527		116,266
Long-term debt	—		24,800
Other noncurrent liabilities	31,796		54,306
Noncurrent liabilities held for sale	$	31,796	$	79,106

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 $419 million of deferred tax benefits related to NRG are included in discontinued operations assets listed above as of June 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 six months ended June 30, 2004.

3. Tax Matters — Corporate-Owned Life Insurance

Interest Expense Deductibility — P.S.R. Investments, Inc. (PSRI), a wholly owned subsidiary of Public Service Company of Colorado (PSCo), a utility subsidiary of Xcel Energy, owns and manages permanent life insurance policies, known as corporate-owned life insurance (COLI) policies, on some of PSCo’s current and former employees. At various times, borrowings have been made against the cash values of these COLI policies and deductions taken on the interest expense on these borrowings. The Internal Revenue Service (IRS) has challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through 2001.

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

In April 2004, Xcel Energy filed a lawsuit in U.S. District Court for the District of Minnesota against the IRS to establish its entitlement to deduct policy loan interest for tax years 1993 and 1994. 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. Xcel Energy requested that the tax court consolidate and stay its petitions pending the decision in the district court litigation. On May 2, 2005, Xcel Energy filed a motion for summary judgment in the district court litigation. On June 22, 2005, the government also filed a summary judgment motion arguing, for the first time, that Xcel Energy lacked an insurable interest in the lives of its employees, and therefore, the policies are allegedly void. Xcel Energy denies that this claim has any merit. A court hearing is scheduled for August 19, 2005 to hear both motions. The litigation could require several years to reach final resolution. Although the ultimate resolution of this matter is uncertain, it could have a material adverse effect on Xcel Energy’s financial position and results of operations and cash flows. Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding.

Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2005, would reduce earnings by an estimated $350 million. In 2004, Xcel Energy received formal notification that the IRS will seek penalties. If penalties (plus associated interest) also are included, 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, which 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. If adopted as proposed, the interpretation will be 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. The exposure draft requires a 60-day comment period, which will be followed by deliberations. Accordingly, if adopted as proposed, Xcel Energy would report as a cumulative effect of a change in accounting principle in its 2005 income statement a charge of approximately $350 million relating to COLI tax benefits and additional interest costs. Under the proposed interpretation 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.

4. Rates and Regulation

Federal Regulation

Market-Based Rate Authority — The Federal Energy Regulatory Commission (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’s 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 August 12, 2005. Because of the commencement of the Midwest Independent Transmission System Operator, Inc. (MISO) Day 2 market and the FERC’s decision consistent with other precedent to analyze NSP-Minnesota and NSP-Wisconsin as part of that larger market, 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.

By August 1, 2005, SPS and PSCo must either submit a delivered price test analysis to support the grant of market-based rate authorization for sales within their control areas, make a mitigation proposal to eliminate any ability that they have to exercise market power, or adopt the FERC’s default mitigation proposal, namely to adopt cost-based rates that would apply to sales within their control areas. Xcel Energy plans to withdraw its market-based rate authority on a prospective basis for sales with loads sinking within the PSCo and SPS control areas. SPS expects to make wholesale sales in these two control areas based on cost-based arrangements. The cost-based rate that will be proposed for PSCo and SPS is not expected to have a significant impact on commodity marketing 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 Complaint – 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 the case is set to go to hearing in December 2005. The complainants’ initial testimony was filed on July 12, 2005, and SPS is reviewing the testimony and preparing its answering testimony that is due August 23, 2005. Hearings are scheduled for December 2005.

Independent Transmission System Operators

MISO Operations (NSP-Minnesota and NSP-Wisconsin) — In August 2000, NSP-Minnesota and NSP-Wisconsin joined the MISO. In December 2001, the FERC approved the MISO as the first regional transmission organization (RTO) in the United States under FERC Order No. 2000. On Feb. 1, 2002, the MISO began interim operations, including regional transmission tariff administration services for the NSP-Minnesota and NSP-Wisconsin electric transmission systems. In 2002, NSP-Minnesota and NSP-Wisconsin received all required regulatory approvals to transfer functional control of their high voltage (100 kilovolts and above) transmission systems to the MISO. The MISO membership grants MISO functional control over the operations of these facilities. MISO also provides reliability coordination services for the facilities of certain neighboring electric utilities.

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. To date, the information systems required to operate the market have performed satisfactorily. However, during the initial days of operation, MISO centrally dispatched generation in a manner different than pre-market individual utility dispatch, with more dispatch of natural gas and oil fired peaking units for similar load and weather conditions. MISO has stated that energy imports from coal and hydro generation located outside the MISO region were also substantially lower than in pre-market periods. It is possible that these conditions are short-term implementation issues related to the complexity of centralized market operations and market participant inexperience. In early April 2005, the FERC sent letters to several MISO market participants, including Xcel Energy, with questions regarding generation price offers submitted to MISO in comparison to reference prices calculated by the MISO independent market monitor. Xcel Energy submitted a timely response to the FERC letter. On July 21, 2005, the FERC announced it was closing its investigation of the offers. Xcel Energy does not expect any further FERC follow-up regarding the reference price calculations. Xcel Energy and other market participants are actively working 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 is also considering its regulatory and other options if the initial market operation issues continue.

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. Xcel Energy and other market participants have disputed certain transactions, some of which are discussed above, and the resolution of these items could impact Xcel Energy’s results of operations.

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. Under the current FCA mechanism in Minnesota, NSP-Minnesota is allowed full recovery of its fuel and purchased energy costs. The proposal would allow recovery of locational marginal pricing market costs, including congestion and marginal loss costs, which would be netted by revenues generated by financial transmission rights and revenues received that are related to marginal compensation loss costs, as well as MISO energy market operations costs. NSP-Minnesota sought recovery effective with the beginning of the energy market on April 1, 2005, and the deferral of costs incurred prior to MPUC action. On April 7, 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 all net costs associated with implementation of the MISO Day 2 market, to be effective April 1, 2005. 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. Because it is difficult to predict or quantify the costs or benefits, the deferral order provides temporary protection to both utilities and customers, until a long-term solution regarding recovery of Day 2 costs can be designed and implemented. As with the interim orders granted in the Minnesota, North Dakota and South Dakota jurisdictions, the PSCW’s relief is subject to refund until the merits of the case are determined. 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.

MISO Arbitration (NSP-Minnesota and NSP-Wisconsin) - In March 2005, an arbitrator issued a decision in the arbitration between American Transmission Company, LLC (ATC) and the MISO regarding the distribution of approximately $11.5 million of transmission service revenues related to certain transmission service reservations under the MISO open access transmission tariff. This was the first arbitration conducted under the dispute resolution procedures of the MISO agreement. NSP-Minnesota and NSP-Wisconsin participated in the proceeding in support of the MISO position that the revenue distribution to ATC was erroneous and the revenues should instead be shared among all MISO transmission owners retroactive to Feb. 1, 2002, when the error occurred. The arbitrator ruled the revenue distribution should be corrected, but prospective from Aug. 1, 2004. A refund retroactive to Aug. 1, 2004 results in a refund of approximately $0.8 million to NSP-Minnesota and NSP-Wisconsin. The proceeds were received in March 2005. No party has requested FERC review of the award, so Xcel Energy believes the matter is now complete.

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 and is expected to have a positive impact on 2005 results.

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. Interim rates collecting $6.4 million per year were implemented December 1, 2004, subject to refund.

On April 19, 2005, NSP-Minnesota and the Department of Commerce filed with an administrative law judge and the MPUC an offer of settlement related to the natural gas rate case. The settlement agreement includes an annual rate increase of $5.8 million, based on a return on equity of 10.4 percent. The settlement also reflects an increase in the residential customer charge from $6.50 to $8.00 per month. The administrative law judge issued a report to the MPUC recommending approval of the settlement agreement. The Office of the Attorney General filed exceptions to the report regarding the residential customer charge issue. On July 21, 2005, the MPUC voted to approve the settlement agreement with one slight modification on the reconnection fee that does not impact the revenue deficiency. A final order is expected by Aug. 22, 2005.

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. 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.

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 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 Public Service Commission of Wisconsin (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. 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. Final rates will be determined later in 2005 after a full audit and public hearing, and will remain in effect until new rates set in the 2006 rate case are implemented. The public hearing has been tentatively scheduled for Aug. 23, 2005.

NSP-Wisconsin 2006 General Rate Case - On June 1, 2005, NSP-Wisconsin filed a general rate case application for 2006, in accordance with the biennial rate case-filing schedule established by the PSCW. In the application, NSP-Wisconsin requested an increase of $40.8 million, or 10.3 percent, for the Wisconsin retail electric jurisdiction, and an increase of $7 million, or 4.4 percent, for the Wisconsin natural gas jurisdiction. The indicated revenue deficiencies are based on a 2006 test year, the currently authorized 11.90 percent return on equity and a common equity ratio of 56.32 percent. The increase is necessary to maintain and improve existing facilities, as well as to invest in new facilities to meet growing customer needs. Also contributing to the electric increase are rising fuel and purchased power costs. NSP-Wisconsin has requested the new rates be effective Jan. 1, 2006. On July 22, 2005, the PSCW held a pre-hearing conference. Hearings are scheduled for November 2005.

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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 its future resource plan. As a part of the settlement the CPUC approved PSCo’s plan to construct a 750-megawatt net output pulverized coal-fired unit at the Comanche Station located near Pueblo, Colo. and transfer up to 250 megawatts of capacity ownership from the 750-megawatt unit to Intermountain Rural Electric Association (IREA) and Holy Cross Energy, if negotiations with those entities are successful.

On July 20, 2005, Holy Cross Energy filed a lawsuit requesting declaratory judgment regarding their rights to participate in the Comanche 3 project. PSCo is in discussions with Holy Cross Energy to resolve the difference between the parties.

On April 12, 2005, PSCo signed agreements with IREA that define the respective rights and obligations of PSCo and IREA in the transfer of 25 percent of the capacity ownership of the new 750-megawatt Comanche unit to IREA. Transfer of ownership to IREA is contingent upon IREA’s successful completion of its financing, among other things, and is expected to occur in late 2005 or early 2006.

On April 8, 2005, the Colorado Department of Public Health and Environment issued draft air quality permits for the new Comanche unit for public comment. On July 5, 2005, final air quality permits were issued for the new coal-fired unit, as well as additional emission controls on Comanche’s two existing units. Construction on the plant is planned to commence in the fall of 2005.

On Feb. 16, 2005, PSCo filed an application with the CPUC for a certificate of public convenience and necessity for construction of the transmission associated with the new Comanche unit. The transmission project consists of:

• Construction of a new double circuit 345-kilovolt transmission facility between Comanche station and Midway substation;

• Installation of autotransformers to allow an existing double circuit transmission facility operating at 230 kilovolts between Midway substation and the Daniels Park substation to operate at 345 kilovolts and

• Reconstruction of an existing facility to a double circuit 345-kilovolt capable facility, but operated initially at 230 kilovolts.

The CPUC set this matter for hearing before an administrative law judge and hearings were held regarding PSCo’s application in June 2005. A decision is expected later this year.

On June 10, 2005, PSCo filed a petition with the City of Pueblo, Colo. requesting that the city annex the Comanche power plant. This petition is scheduled for a final determination by the Pueblo City Council on Sept. 12, 2005. Construction cannot begin without the necessary permits. If annexation is denied, PSCo will petition for construction permits through Pueblo County. PSCo cannot predict the outcome of this request.

Effective July 19, 2005, PSCo secured a long-term water supply contract with the Pueblo Board of Water Works for all three Comanche units. The agreement is predicated on the approval of annexation of the plant site into the City of Pueblo.

In addition to the new Comanche unit and PSCo demand side management (DSM) approved in the settlement agreement, the remainder of PSCo’s resource needs will be met by the least cost combination of purchases of renewable energy, supply side resources, and contracted DSM.

PSCo issued a renewable energy request for proposal (RFP) on August 17, 2004. In November, 2004, PSCo received 33 bids for approximately 4,600 megawatts of wind and other renewable generation. In February and March 2005 PSCo entered into contracts to purchase the energy from two wind generation projects, a 60-megawatt project and 69-megawatt project, each to be constructed in 2005.

On Feb. 24, 2005, PSCo issued an all-source solicitation, comprised of RFPs for dispatchable resources, non-dispatchable resources and DSM resources, seeking approximately 2,500 megawatts of additional electric supply and demand-side resources that are scheduled to begin providing service in 2006 through 2013. 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 DSM. PSCo is in the process of evaluating the bids received in response to the RFP and expects to begin negotiations with the winning projects later this year.

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 has received two rounds of comments with respect to proposed rules and has scheduled three days of hearings beginning Aug. 30, 2005 regarding the rulemaking. Final rules are expected to become effective later this year.

PSCo Natural Gas Rate Case – On May 27, 2005, PSCo filed for an increase of natural gas base rates in Colorado. The proposed increase, factoring in current costs of natural gas, would increase overall customer bills by approximately $34 million, or 3 percent annually. PSCo supplemented its filing with the CPUC on July 8, 2005. The CPUC has scheduled a prehearing conference for Aug. 3, 2005. It is anticipated that the request, if approved by the CPUC, would become effective early in 2006.

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 settlement and request a hearing was July 22, 2005. No parties protested the settlement agreement. The PUCT will consider the settlement agreement for approval. If the PUCT does not approve the filed stipulation without modification, SPS, as well as the other signatories have the option of withdrawing from the stipulation. If the stipulation is not approved as submitted, it is likely that one or more signatories will withdraw. If this occurs, the PUCT could revert to the consideration of the PFD. It is uncertain as to whether the PUCT will approve the stipulation or will adopt any or all of the administrative law judge’s recommendations contained in the PFD. The settlement 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. A PUCT decision is expected late in 2005.

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 (ERCOT) in the Southwest Power Pool 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 fourth quarter of 2005.

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, purchased power cost adjustment clause (FPPCAC) for the period of October 1, 2001 through August 2004. Several parties have requested to expand the issues in the case. The case is pending further action by the NMPRC. SPS’ next fuel and purchased power cost adjustment factor continuation filing in New Mexico is due August 19, 2005.

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.

Clean Air Interstate and Mercury Rules - In March 2005, the Environmental Protection Agency (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 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.

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 Clean Air Act’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 Clean Air Act 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 Clean Air Act 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 Clean Air Act 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 Clean Air Act, 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 Clean Air Act at the Comanche plant. The notice of intent to sue alleges PSCo has violated the Clean Air Act’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 Clean Air Act 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 $2.7 million during 2005 and 2006.

Legal Contingencies

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

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

Fru-Con Construction Corporation v. Utility Engineering, et al. – On March 28, 2005, Fru-Con Construction Corporation (Fru-Con) commenced a lawsuit in United States 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.

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.

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 U.S. District Judge Pro in Nevada, who is supervising western area wholesale natural gas marketing litigation. 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. The court has not reached a decision concerning this motion.

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 5 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 June 30, 2005, Xcel Energy and its subsidiaries had approximately $295 million of commercial paper outstanding at a weighted average interest rate of 3.33 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 June 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 subsidiaries. The latest expiration for the bond indemnities is 2022. The total amount of bonds with this indemnity outstanding as of June 30, 2005, was approximately $137.6 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. Statement of Financial Accounting Standard (SFAS) No. 133 – “Accounting for Derivative Instruments and Hedging Activities,” as amended, (SFAS No. 133) requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

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 June 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. 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 June 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. However, due to the volatility of commodities markets, the value in Other Comprehensive Income will likely change prior to its recognition in earnings.

Xcel Energy and its subsidiaries enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. Xcel Energy expects to recognize in earnings during the next 12 months net gains from Other Comprehensive Income related to interest cash flow hedge contracts of approximately $0.4 million.

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 second 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 June 30,
(Millions of Dollars)	2005			2004

Accumulated other comprehensive income related to cash flow hedges at March 31	$	1.9		$	2.6
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges	(22.0		)	16.7
After-tax net realized gains on derivative transactions reclassified into earnings	(2.3		)	(1.2		)
Accumulated other comprehensive income (loss) related to cash flow hedges at June 30	$	(22.4	)	$	18.1

	Six months ended June 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	(17.9		)	13.8
After-tax net realized gains on derivative transactions reclassified into earnings	(4.6		)	(3.8		)
Accumulated other comprehensive income (loss) related to cash flow hedges at June 30	$	(22.4	)	$	18.1

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 six months ended June 30 consists of the following:

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

Interest income	4,444			3,465
Equity income in unconsolidated affiliates	1,185			97
Other nonoperating income	3,192			1,190
Gain on the sale of assets	2,101			1,936
Minority interest income (loss)	408			(24		)
Interest expense on corporate-owned life insurance, net of increase in cash surrender value	(4,841		)	(4,617		)
Other nonoperating expense	(1,423		)	(2,343		)
Total interest and other income, net of nonoperating expenses	$	5,066		$	(296	)

	Six months ended June 30,
(Thousands of Dollars)	2005			2004

Interest income	7,510			7,039
Equity income in unconsolidated affiliates	3,562			943
Other nonoperating income	4,455			2,187
Gain on the sale of assets	1,980			1,557
Minority interest income (loss)	519			(7		)
Interest expense on corporate-owned life insurance, net of increase in cash surrender value	(9,536		)	(8,343		)
Other nonoperating expense	(2,933		)	(4,093		)
Total interest and other income, net of nonoperating expenses	$	5,557		$	(717	)

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 six months ending June 30, 2005 and 2004:

	Three months ended June 30, 2005						Three months ended June 30, 2004
(Amounts in thousands, except per share amounts)	Income			Shares	Per-share Amount		Income			Shares	Per-share Amount
Income from continuing operations	$	78,410					$	85,514
Less: Dividend requirements on preferred stock	(1,060		)				(1,060		)
Basic earnings per share:
Income from continuing operations	77,350			402,214	$	0.19	84,454			399,217	$	0.21
Effect of dilutive securities:
$230 million convertible debt	2,896			18,654			3,046			18,654
$57.5 million convertible debt	724			4,663			761			4,663
Stock options	—			21			—			11
Diluted earnings per share:
Income from continuing operations and assumed conversions	$	80,970		425,552	$	0.19	$	88,261		422,545	$	0.21

	Six months ended June 30, 2005						Six months ended June 30, 2004
(Amounts in thousands, except per share amounts)	Income			Shares	Per-share Amount		Income			Shares	Per-share Amount
Income from continuing operations	$	204,292					$	234,646
Less: Dividend requirements on preferred stock	(2,120		)				(2,120		)
Basic earnings per share:
Income from continuing operations	202,172			401,668	$	0.50	232,526			398,900	$	0.59
Effect of dilutive securities:
$230 million convertible debt	5,707			18,654			5,849			18,654
$57.5 million convertible debt	1,427			4,663			1,462			4,663
Stock options	—			19			—			16
Diluted earnings per share:
Income from continuing operations and assumed conversions	$	209,306		425,004	$	0.49	$	239,837		422,233	$	0.57

10. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three months ended June 30,
	2005			2004			2005			2004
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits

Service cost	$	12,980		$	13,124		$	1,599		$	1,425
Interest cost	39,496			44,499			13,663			13,402
Expected return on plan assets	(69,484		)	(79,307		)	(6,267		)	(6,351		)
Amortization of transition (asset) obligation	—			(2		)	3,644			3,590
Amortization of prior service cost (credit)	7,496			7,405			(544		)	(540		)
Amortization of net (gain) loss	(39		)	(2,577		)	6,460			5,276
Net periodic benefit cost (credit)	(9,551		)	(16,858		)	18,555			16,802
Settlements and curtailments	—			703			—			—
Credits not recognized due to the effects of regulation	6,500			8,568			—			—
Additional cost recognized due to the effects of regulation	—			—			973			972
Net benefit cost (credit) recognized for financial reporting	$	(3,051	)	$	(7,587	)	$	19,528		$	17,774

	Six months ended June 30,
	2005			2004			2005			2004
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits

Service cost	$	30,230		$	29,474		$	3,342		$	3,050
Interest cost	80,492			82,674			27,530			26,302
Expected return on plan assets	(139,758		)	(151,532		)	(12,850		)	(11,626		)
Amortization of transition (asset) obligation	—			(4		)	7,289			7,290
Amortization of prior service cost (credit)	15,018			15,006			(1,089		)	(1,090		)
Amortization of net (gain) loss	3,410			(7,718		)	13,123			10,826
Net periodic benefit cost (credit)	(10,608		)	(32,100		)	37,345			34,752
Settlements and curtailments	—			703			—			—
Credits not recognized due to the effects of regulation	9,684			18,745			—			—
Additional cost recognized due to the effects of regulation	—			—			1,946			1,945
Net benefit cost (credit) recognized for financial reporting	$	(924	)	$	(12,652	)	$	39,291		$	36,697

Employer Contribution

In July 2005, Xcel Energy contributed $15 million to the PSCo bargaining pension plan.

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 June 30, 2005
Operating revenues from external customers	$	1,720,431		$	326,347		$	20,239	$	—		$	2,067,017
Intersegment revenues	(48		)	3,973			—		(3,925		)	—
Total revenues	$	1,720,383		$	330,320		$	20,239	$	(3,925	)	$	2,067,017
Income (loss) from continuing operations	$	88,751		$	931		$	8,452	$	(19,724	)	$	78,410
Three months ended June 30, 2004
Operating revenues from external customers	$	1,468,340		$	271,634		$	23,125	$	—		$	1,763,099
Intersegment revenues	261			2,205			—		(2,466		)	—
Total revenues	$	1,468,601		$	273,839		$	23,125	$	(2,466	)	$	1,763,099
Income (loss) from continuing operations	$	83,544		$	(2,185	)	$	9,306	$	(5,151	)	$	85,514

(Thousands of Dollars)	Regulated Electric Utility		Regulated Natural Gas Utility		All Other		Reconciling Eliminations			Consolidated Total
Six months ended June 30, 2005
Operating revenues from external customers	$	3,255,378	$	1,161,402	$	43,794	$	—		$	4,460,574
Intersegment revenues	310		5,098		—		(5,408		)	—
Total revenues	$	3,255,688	$	1,166,500	$	43,794	$	(5,408	)	$	4,460,574
Income (loss) from continuing operations	$	164,140	$	52,196	$	18,722	$	(30,766	)	$	204,292
Six months ended June 30, 2004
Operating revenues from external customers	$	2,934,594	$	1,031,358	$	48,365	$	—		$	4,014,317
Intersegment revenues	544		5,661		—		(6,205		)	—
Total revenues	$	2,935,138	$	1,037,019	$	48,365	$	(6,205	)	$	4,014,317
Income (loss) from continuing operations	$	188,869	$	46,049	$	14,862	$	(15,134	)	$	234,646

12. Subsequent Event

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 December 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.

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 June 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 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 investment;

• 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 June 30,						Six months ended June 30,
Contribution to Earnings (Millions of dollars)	2005			2004			2005			2004

GAAP income (loss) by segment
Regulated electric utility segment income — continuing operations	$	88.7		$	83.6		$	164.1		$	188.9
Regulated natural gas utility segment income — continuing operations	0.9			(2.2		)	52.2			46.0
Other utility results (a)	4.8			7.4			12.8			11.7
Utility segment income — continuing operations	94.4			88.8			229.1			246.6

Other nonregulated results and holding company costs (a)	(16.0		)	(3.3		)	(24.8		)	(12.0		)
Income — continuing operations	78.4			85.5			204.3			234.6

Regulated utility income — discontinued operations	—			0.6			0.2			1.4
Other nonregulated income — discontinued operations	5.0			0.2			0.4			0.2
Income — discontinued operations	5.0			0.8			0.6			1.6
Total GAAP income	$	83.4		$	86.3		$	204.9		$	236.2

	Three months ended June 30,						Six months ended June 30,
	2005			2004			2005			2004

GAAP earnings per share contribution by segment
Regulated electric utility segment — continuing operations	$	0.21		$	0.20		$	0.39		$	0.44
Regulated natural gas utility segment — continuing operations	—			(0.01		)	0.12			0.11
Other utility results (a)	0.01			0.02			0.03			0.03
Utility segment earnings per share — continuing operations	0.22			0.21			0.54			0.58

Other nonregulated results and holding company costs (a)	(0.03		)	—			(0.05		)	(0.01		)
Earnings per share — continuing operations	0.19			0.21			0.49			0.57

Regulated utility earnings — discontinued operations	—			—			—			—
Other nonregulated earnings — discontinued operations	0.01			—			—			—
Earnings per share — discontinued operations	0.01			—			—			—
Total GAAP earnings per share - diluted	$	0.20		$	0.21		$	0.49		$	0.57

(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 six months ended June 30, 2005 earnings per share compared with the same period in 2004, which are discussed in more detail later.

Increase (decrease)	Three months ended June 30, 2005 vs. 2004			Six months ended June 30, 2005 vs. 2004
2004 Earnings per share – diluted	$	0.21		$	0.57

Components of change – 2005 vs. 2004
Higher base electric utility margins	0.08			0.10
Lower short-term wholesale and commodity trading margins	—			(0.03		)
Higher depreciation and amortization expense	(0.03		)	(0.06		)
Higher operating and maintenance expense	(0.06		)	(0.07		)
Effective tax rate changes and other	(0.01		)	(0.02		)
Net change in earnings per share – continuing operations	(0.02		)	(0.08		)

Changes in Earnings Per Share – Discontinued Operations	0.01			0.00

2005 Earnings per share – diluted	$	0.20		$	0.49

Utility Segment Results

Earnings for the second quarter of 2005 increased due to higher electric margins, partially offset by increased operating and maintenance expense, and higher depreciation expense. 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 June 30	$	0.01	$	(0.02	)	$	0.03
Six months ended June 30	$	0.00	$	(0.03	)	$	0.03

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 June 30,						Six months ended June 30,
	2005			2004			2005			2004

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

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.

Discontinued Operations

Results from discontinued operations were a gain of 1 cent per share for the second quarter of 2005 and 0 cents per share for the first six months of 2005. In March 2005, Xcel Energy agreed to sell its non-regulated subsidiary, UE, to Zachry Group, Inc. In April 2005, Zachry acquired all of the outstanding shares of UE. Quixx Corp., a subsidiary of UE that partners in cogeneration projects was not included in the transaction. Xcel Energy recorded an immaterial loss on the transaction in the first quarter of 2005.

Discontinued - Utility Segments – During 2004, Xcel Energy reached an agreement to sell its regulated electric and natural gas subsidiary, CLF&P. The sale was completed in January 2005.

Discontinued – All Other – In March 2005, Xcel Energy agreed to sell its non-regulated subsidiary, UE to Zachry Group, Inc., as discussed above.

On Sept. 27, 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren Innovations, Inc., a wholly owned broadband communications services subsidiary. Seren delivers cable television, high-speed Internet and telephone service. Xcel Energy expects to complete the sale in the latter half of 2005.

In 2004, Xcel Energy exited all business conducted by its nonregulated subsidiary, e prime, and most conducted by Xcel Energy International. Xcel Energy sold all of the contractual assets of e prime and closed on the sale of one of the Argentina subsidiaries of Xcel Energy International during the first quarter of 2004. The sale price was immaterial and approximated the book value of Xcel Energy’s investment.

Income Statement Analysis — Second Quarter 2005 vs. Second Quarter 2004

Electric Utility, Short-term Wholesale and Commodity Trading Margins

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

Xcel Energy has two distinct forms of wholesale sales: short-term wholesale and commodity trading. Short-term wholesale refers to energy related purchase and sales activity and the use of certain financial instruments associated with the fuel required for and energy produced from Xcel Energy’s generation assets or the energy and capacity purchased to serve native load. Commodity trading is not associated with Xcel Energy’s generation assets or the energy and capacity purchased to serve native load. Short-term wholesale and commodity trading activities are considered part of the electric utility segment.

Xcel Energy’s commodity trading operations are conducted by NSP-Minnesota, PSCo and SPS. Margins from commodity trading activities are partially redistributed among these operating utilities of Xcel Energy, pursuant to a joint operating agreement (JOA) approved by the FERC. On a consolidated basis, the impact of the JOA is eliminated. Short-term wholesale and commodity trading margins reflect the estimated impacts of regulatory sharing, if applicable. Commodity trading revenues are reported net of related costs (i.e., on a margin basis) in the Consolidated Statements of Operations. Commodity trading costs include fuel, purchased power, transmission and other related costs.

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 June 30, 2005
Electric utility revenue (excluding commodity trading)	$	1,655		$	58		$	—		$	1,713
Electric fuel and purchased power	(878		)	(34		)	—			(912		)
Commodity trading revenue	—			—			115			115
Commodity trading costs	—			—			(108		)	(108		)
Gross margin before operating expenses	$	777		$	24		$	7		$	808
Margin as a percentage of revenue	46.9		%	41.4		%	6.1		%	44.2		%

Three months ended June 30, 2004
Electric utility revenue (excluding commodity trading)	$	1,408		$	59		$	—		$	1,467
Electric fuel and purchased power	(691		)	(32		)	—			(723		)
Commodity trading revenue	—			—			150			150
Commodity trading costs	—			—			(149		)	(149		)
Gross margin before operating expenses	$	717		$	27		$	1		$	745
Margin as a percentage of revenue	50.9		%	45.8		%	0.7		%	46.1		%

Short-term wholesale and commodity trading margins increased approximately $3 million during the second quarter of 2005.

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

Base Electric Utility Revenue

(Millions of dollars)	2005 vs. 2004

Sales growth (excluding weather impact)	$	26
Estimated impact of weather	28
Fuel and purchased power cost recovery	155
Capacity sales	4
Firm wholesale	21
Quality of Service obligations	7
Purchased capacity cost adjustment	7
Other	(1		)
Total base electric utility revenue increase	$	247

Base Electric Utility Margin

(Millions of dollars)	2005 vs. 2004

Sales growth (excluding weather impact)	$	25
Estimated impact of weather	22
Purchased capacity costs	(1		)
Quality of service obligations	7
Renewable development fund and conservation revenues	3
Capacity sales	4
Total base electric utility margin increase	$	60

Base electric utility revenues and margins increased largely due to weather-normalized retail electric sales growth of approximately 2.3 percent, favorable weather and higher capacity sales in Colorado. Also increasing revenues were higher fuel and purchased power costs, which are largely passed through to customers. Partially offsetting the higher revenues and margins were higher purchased capacity costs, primarily at PSCo.

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 June 30,
(Millions of dollars)	2005			2004

Natural gas utility revenue	$	326		$	272
Cost of natural gas sold and transported	(232		)	(186		)
Natural gas utility margin	$	94		$	86

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

Natural Gas Revenue

(Millions of dollars)	2005 vs. 2004
Sales growth, excluding weather impacts	2
Estimated impact of weather on firm sales volume	(1		)
Purchased gas adjustment clause recovery	49
Base rate changes – Minnesota	1
Transportation and other	3
Total natural gas revenue increase	$	54

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	2
Base rate changes – Minnesota	1
Transportation and other	5
Total natural gas margin increase	$	8

Nonregulated Operating Margins

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

	Three Months Ended June 30,
(Millions of Dollars)	2005			2004

Nonregulated and other revenue	$	20		$	23
Nonregulated cost of goods sold	(7		)	(10		)
Nonregulated margin	$	13		$	13

Non-Fuel Operating Expense and Other Costs

Other Operating and Maintenance Expenses – Utility – Other operating and maintenance expenses for the second quarter of 2005 increased by approximately $45 million, or 11.4 percent, compared with the same period in 2004. The increase is primarily due to a planned nuclear plant refueling and upgrade outage in 2005, with no comparable outage in the second quarter of 2004, which increased costs by approximately $20 million. In addition, employee benefit costs increased approximately $10 million compared with 2004, and performance-based compensation costs were approximately $7 million higher in 2005 than 2004. The accruals for these performance-based plans fluctuate based on Xcel Energy’s stock price, which can create variances on a quarter-to-quarter basis.

Depreciation and Amortization – Depreciation and amortization expense increased by approximately $20 million, or 11.8 percent, for the second 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, depreciation expense increased for other plant additions.

Income taxes — Income taxes for continuing operations increased by $9 million for the second quarter of 2005 compared with the same period in 2004. The effective tax rate for continuing operations was 24.0 percent for the second quarter of 2005, compared with 15.7 percent for the same period in 2004. Additional income tax expense was recorded in the second quarter of 2005 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. Second quarter 2005 and second quarter 2004 had lower actual effective tax rates as compared to forecast due to a variation in the year-to-date levels and mix of income earned in various jurisdictions with different tax rates.

Income Statement Analysis — First Six Months of 2005 vs. First Six 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
Six months ended June 30, 2005
Electric utility revenue (excluding commodity trading)	$	3,157		$	91		$	—		$	3,248
Electric fuel and purchased power	(1,622		)	(52		)	—			(1,674		)
Commodity trading revenue	—			—			232			232
Commodity trading costs	—			—			(225		)	(225		)
Gross margin before operating expenses	$	1,535		$	39		$	7		$	1,581
Margin as a percentage of revenue	48.6		%	42.9		%	3.0		%	45.4		%

Six months ended June 30, 2004
Electric utility revenue (excluding commodity trading)	$	2,813		$	117		$	—		$	2,930
Electric fuel and purchased power	(1,349		)	(53		)	—			(1,402		)
Commodity trading revenue	—			—			236			236
Commodity trading costs	—			—			(231		)	(231		)
Gross margin before operating expenses	$	1,464		$	64		$	5		$	1,533
Margin as a percentage of revenue	52.0		%	54.7		%	2.1		%	48.4		%

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

Base Electric Utility Revenue

(Millions of dollars)	2005 vs. 2004
Fuel and purchased power cost recovery	$	221
Sales growth (excluding weather impact)	29
Firm wholesale	39
Estimated impact of weather	25
Quality of service obligations	7
Renewable development fund (offset by decrease in depreciation expense)	3
Capacity sales	8
Purchased capacity cost adjustment	14
Other	(2		)
Total base electric utility revenue increase	$	344

Base Electric Utility Margin

(Millions of dollars)	2005 vs. 2004
Sales growth (excluding weather impact)	$	28
Estimated impact of weather	19
Purchased capacity costs	(8		)
Quality of service obligations	7
Renewable development fund and conservation revenues	5
Financial hedging costs	4
Capacity sales	8
Regulatory accruals and other	8
Total base electric utility margin increase	$	71

Short-term wholesale and commodity trading margins decreased $23 million for the first six months of 2005 compared with the same period in 2004. The lower results reflect a number of market factors, including higher market prices and additional resources available for sale in 2004 and a pre-existing contract, which expired in the first quarter of 2004. A comparable contract was not in place in the first half of 2005.

Natural Gas Utility Margins

	Six Months Ended June 30,
(Millions of Dollars)	2005			2004
Natural gas utility revenue	$	1,161		$	1,031
Cost of natural gas sold and transported	(901		)	(781		)
Natural gas utility margin	$	260		$	250

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

Natural Gas Revenue

(Millions of dollars)	2005 vs. 2004
Purchased gas adjustment clause recovery	$	135
Estimated impact of weather on firm sales volume	(5		)
Sales growth (excluding weather impact)	$	2
Transportation and other	(2		)
Total natural gas revenue increase	$	130

Natural Gas Margin

(Millions of dollars)	2005 vs. 2004
Sales growth (excluding weather impact)	$	2
Estimated impact of weather on firm sales volume	—
Transportation and other	8
Total natural gas margin increase	$	10

Nonregulated Operating Margins

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

	Six Months Ended June 30,
(Millions of Dollars)	2005			2004
Nonregulated and other revenue	$	44		$	48
Nonregulated cost of goods sold	(18		)	(22		)
Nonregulated margin	$	26		$	26

Non-Fuel Operating Expense and Other Costs

Other Operating and Maintenance Expenses – Utility – Other operating and maintenance expenses for the first six months of 2005 increased $54 million, or 6.8 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 six months of 2004, increased costs by approximately $44 million. In addition, employee benefit costs were approximately $14 million higher in 2005 than 2004. The increases were partially offset by lower maintenance costs at the fossil-fuel plants of approximately $10 million.

Depreciation and Amortization – Depreciation and amortization expense increased by approximately $43 million, or 12.4 percent, for the first six-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, depreciation expense increased for other plant additions.

Income taxes – Income taxes for continuing operations decreased by $18 million for the first six months of 2005 compared with the same period in 2004. The effective tax rate for continuing operations was 25.6 percent for the first six months of 2005, compared with 27.3 percent for the same period in 2004. The decrease in the effective tax rate was due to additional tax credits and lower pretax income levels for the first six months of 2005 as compared with the same period in 2004, partially offset by the additional income tax expense recorded, as discussed above.

Factors Affecting Results of Continuing Operations

Fuel Supply and Costs

PSCo and SPS recently notified the United States Department of Energy (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 PSCo in the operation of its two coal-fired electric generating stations and the primary source used by SPS in the operation of a number of its coal-fired electric generating stations. Reduced deliveries of coal have reduced the inventories of coal at PSCo and SPS 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 are working with Xcel Energy to identify options in the interim to increase the rate of coal deliveries. Additionally, Xcel Energy has been analyzing the potential magnitude, likelihood and effects of reduced coal deliveries to PSCo’s and SPS’ generating stations and developing an interim plan to conserve coal. The interim plan includes modifying the dispatch of their coal-fired electric generating stations to conserve existing coal supplies until coal deliveries return to normal levels. 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 have been in contact with their wholesale customers to identify options to reduce sales levels if necessary. PSCo also anticipates utilizing larger capacity rail cars to help mitigate coal supply issues. Based upon these cooperative efforts, including improvements in scheduling and operating practices, Xcel Energy is optimistic that PSCo may be able to substantially reduce its use of natural gas later this summer.

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 will increase 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 ECA provides for an $11.25 million cap on any cost sharing over or under an 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 will recover the increased fuel and purchased energy costs greater than the cap from its customers. At June 30, 2005, no accrual either positive or negative had been recorded relative to the ECA incentive mechanism.

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 for and obtain recovery of higher fuel and purchased energy costs resulting from the disruption in deliveries of coal to its electric generating stations.

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 PSCo and SPS believe that they should be allowed to recover these higher costs, if all or a significant portion of these higher costs are not recovered or there is a significant lag in recovery, this could have a significant impact on the 2005 financial results of PSCo and/or SPS and possibly Xcel Energy.

While operations 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 has recently determined to implement 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 are expected to increase 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 any 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. At this time NSP-Wisconsin believes the disruption in coal deliveries and subsequent increase in production costs meets the definition of an emergency under the applicable rules, and plans to file an application with the PSCW in August, 2005 requesting deferred accounting treatment.

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 June 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 June 30, 2005, is as follows:

(Millions of Dollars)	Period Ended June 30, 2005		Change from Period Ended March 31, 2005			VaR Limit		Average		High		Low

Commodity Trading (1)	$	1.10	$	(0.40	)	$	5.0	$	1.50	$	2.20	$	1.10

(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 June 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 six months ended June 30, 2005 and 2004 were as follows:

	Six months ended June 30,
(Millions of Dollars)	2005			2004

Fair value of contracts outstanding at Jan. 1	$	—		$	4.2
Contracts realized or otherwise settled during the period	(6.1		)	(7.7		)
Fair value of trading contract additions and changes during the period	6.9			5.6
Fair value of contracts outstanding at June 30	$	0.8		$	2.1

As of June 30, 2005, the sources of fair value of the commodity trading and hedging net assets are 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	$	(1,418	)				$	(1,418	)
	2	416						416
PSCo	1	945						945
	2	44						44
Total Futures/Forwards Fair Value		$	(13	)				$	(13	)

	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	$	284				$	284
PSCo	2	539					539
Total Options Fair Value		$	823				$	823

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	$	12,459				$	12,459
PSCo	2	1,229					1,229
SPS	1	131					131
Total Futures/Forwards Fair Value		$	13,819				$	13,819

	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	$	(724	)	$		$	$	$	(724	)
NSP-Wisconsin	2	(82		)					(82		)
PSCo	2	(5,844		)	1,105				(4,739		)
Total Options Fair Value		$	(6,650	)	$	1,105	$	$	$	(5,545	)

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 June 30, 2005, a 10-percent increase in market prices over the next 12 months for trading contracts would increase pretax income from continuing operations by approximately $0.4 million, whereas a 10-percent decrease would decrease pretax income from continuing operations by approximately $0.2 million.

Interest Rate Risk

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

At June 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 $8.2 million annually, or approximately $2.1 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 June 30, 2005, a 10-percent increase in prices would have resulted in a net mark-to-market increase in credit risk exposure of $44.1 million, while a decrease of 10-percent would have resulted in a decrease of $30.8 million.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

	Six months ended June 30,
(Millions of Dollars)	2005		2004

Cash provided (used) by operating activities
Continuing operations	$	694	$	714
Discontinued operations	102		(378		)
Total	$	796	$	336

Cash provided by operating activities for continuing operations decreased by $20 million for the first six months of 2005, compared with the first six months of 2004. The 2005 cash used in operating activities for discontinued operations decreased by $480 million due 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.

	Six months ended June 30,
(Millions of Dollars)	2005			2004

Cash provided (used) by investing activities
Continuing operations	$	(655	)	$	(507	)
Discontinued operations	84			5
Total	$	(571	)	$	(502	)

Cash used in investing activities for continuing operations increased by $148 million for the first six months of 2005, compared with the first six months of 2004. This is largely due to increased capital expenditures in 2005 and the availability of previously restricted cash in 2004. Cash provided by discontinued operations increased $79 million in 2005 compared to 2004. The increase was primarily due to the receipt of proceeds from the sale of Cheyenne in 2005.

	Six months ended June 30,
(Millions of Dollars)	2005			2004

Cash used by financing activities
Continuing operations	$	(186	)	$	(265	)
Discontinued operations	—			—
Total	$	(186	)	$	(265	)

Cash used in financing activities for continuing operations decreased by approximately $79 million for the first six months of 2005, compared with the first six months of 2004. The decrease was primarily due to repayments of short-term borrowings and higher dividends paid in 2005. These decreases were offset by increased borrowings on the Xcel Energy 5-year credit facility, fewer stock repurchases and lower repayments of long-term debt in 2005.

Credit Facilities and Other Sources of Liquidity

Xcel Energy and Utility Subsidiary Credit Facilities - As of July 21, 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	$	80	$	295	$	106	$	401	April 2010
PSCo	$	500	$	10	$	490	$	61	$	551	April 2010
SPS	$	250	$	55	$	195	$	—	$	195	April 2010
Xcel Energy – Holding Company	$	600	$	334	$	266	$	3	$	269	Nov. 2009
Total	$	1,725	$	479	$	1,246	$	170	$	1,416

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

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

NSP-Wisconsin has approval from the Wisconsin Public Service Commission to borrow up to $50 million in short-term debt from either external financial institutions or NSP-Minnesota. Currently, NSP-Wisconsin borrows on a short-term basis through an inter-company borrowing agreement with NSP-Minnesota. At June 30, 2005, NSP-Wisconsin had $29.1 million of short-term borrowings outstanding and no 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.

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 A2 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 June 30, 2005, Xcel Energy had $295 million of outstanding commercial paper at a weighted average interest rate of 3.33 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 June 30, 2005, and the SEC approved short-term borrowing limits from the money pool are as follows:

(Millions of Dollars)	Borrowings (Loans)		Total Borrowing Limits
NSP– Minnesota	$	—	$	250
PSCo	$	—	$	250
SPS	$	31.2	$	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 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 December 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 December 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.

PSCo expects to issue $129.5 million of pollution control refunding bonds in the third quarter of 2005. The proceeds of this transaction are expected to be 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.

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

Xcel Energy has identified one change in its internal controls over financial reporting, which occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Xcel Energy’s internal controls over financial reporting. The change relates to new business processes, systems and controls implemented to address the Midwest Independent System Operator (MISO) commencement of “Day 2” operations effective April 1, 2005. See additional discussion in Note 4 to the consolidated financial statements. In addition, 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 4. Submission of Matters to a Vote of Security Holders

Xcel Energy’s Annual Meeting of Shareholders was held on May 25, 2005, for the purpose of voting on the matters listed below. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934, and there were no solicitations in opposition to management’s solicitations. All of management’s nominees for directors as listed in the proxy statement were elected. The voting results were as follows:

1. A proposal to elect eight directors:

Election of Director	Shares Voted For	Withheld Authority
Richard H. Anderson	328,054,345	16,655,330
C. Coney Burgess	327,912,031	16,797,644
A. Barry Hirschfeld	327,770,897	16,938,778
Richard C. Kelly	327,078,792	17,630,883
Ronald M. Moquist	329,049,208	15,660,467
Albert F. Moreno	328,506,378	16,203,297
Ralph R. Peterson	328,039,015	16,670,660
Dr. Margaret R. Preska	327,098,734	17,610,941

2. Proposal to approve the Xcel Energy Inc. 2005 omnibus incentive plan:

Shares Voted For		Shares Voted Against		Shares Abstained		Broker Non-Votes
201,722,130		42,049,871		7,169,248		93,768,426

3. Proposal to approve the Xcel Energy Inc. executive annual incentive award plan (effective May 25, 2005):

Shares Voted For		Shares Voted Against		Shares Abstained		Broker Non-Votes
201,395,078		42,040,415		7,505,756		93,768,426

4. Proposal to approve the ratification of the appointment of Deloitte & Touche LLP as Xcel Energy’s principal independent accountants for 2005:

Shares Voted For		Shares Voted Against		Shares Abstained
332,499,547		7,351,623		4,858,505

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).

4.01		Amendment to the Credit Agreement dated Nov. 4, 2004 between Xcel Energy and various lenders

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).

10.01*		Xcel Energy Inc. 2005 Omnibus Incentive Plan (Appendix B to Schedule 14A, Definitive Proxy Statement filed April 11, 2005, file no. 001-03034)

10.02*		Xcel Energy Inc. Executive Annual Incentive Award Plan (effective May 25, 2005) (Appendix C to Schedule 14A, Definitive Proxy Statement filed April 11, 2005, file no. 001-03034)

10.03*		Amended Employment Agreement, dated as of June 29, 2005, by and between Xcel Energy Inc., a Minnesota corporation, and Wayne H. Brunetti. (Exhibit 10.01 to Xcel Energy Current Report on Form 8-K, dated June 29, 2005)

10.04		Form of Xcel Energy Inc. Omnibus Incentive Plan Performance Share Agreement

10.05		Form of Xcel Energy Inc. Omnibus Incentive Plan Restricted Stock Unit Agreement

10.06		Form of Xcel Energy Inc. Executive Annual Incentive Award Plan Restricted Stock Agreement

10.07		Form of Xcel Energy Inc. Omnibus Incentive Plan Restricted Stock Unit Agreement

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.

SIGNATURES

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

	XCEL ENERGY INC.
	(Registrant)

	/s/ TERESA S. MADDEN
	Teresa S. Madden
	Vice President and Controller

	/s/ BENJAMIN G.S. FOWKE III
	Benjamin G.S. Fowke III
	Vice President and Chief Financial Officer

July 29, 2005

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Xcel Energy (XEL) 10-Q2005 Q2 Quarterly report

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