Edgar Filing: XCEL ENERGY INC

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended Sept. 30, 2010

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

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.)

414 Nicollet Mall
Minneapolis, Minnesota	55401
(Address of principal executive offices)	(Zip Code)

(612) 330-5500

(Registrant’s telephone number, including area code)

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. TYes oNo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). TYes oNo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer T	Accelerated filer £
Non-accelerated filer £ (Do not check if smaller reporting company)	Smaller reporting company £

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). £Yes TNo

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 Oct. 21, 2010
Common Stock, $2.50 par value		460,112,922 shares

TABLE OF CONTENTS

PART I		FINANCIAL INFORMATION
	Item 1 —	Financial Statements (unaudited)
		CONSOLIDATED STATEMENTS OF INCOME	2
		CONSOLIDATED STATEMENTS OF CASH FLOWS	3
		CONSOLIDATED BALANCE SHEETS	4
		CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME	5
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	7
	Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
	Item 3 —	Quantitative and Qualitative Disclosures about Market Risk	62
	Item 4 —	Controls and Procedures	63
PART II		OTHER INFORMATION	63
	Item 1 —	Legal Proceedings	63
	Item 1A —	Risk Factors	63
	Item 6 —	Exhibits	64
SIGNATURES			65
		Certifications Pursuant to Section 302
		Certifications Pursuant to Section 906
		Statement Pursuant to Private Litigation

This Form 10-Q is filed by Xcel Energy Inc. Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado, a Colorado corporation (PSCo); and Southwestern Public Service Company, a New Mexico corporation (SPS). Additional information on the wholly owned subsidiaries is available on various filings with the Securities and Exchange Commission (SEC).

Table of Contents

PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands, except per share data)

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2010			2009			2010			2009
Operating revenues
Electric	$	2,440,917		$	2,128,955		$	6,477,211		$	5,749,207
Natural gas		170,594			169,601			1,210,154			1,224,161
Other		17,276			16,006			56,648			52,819
Total operating revenues		2,628,787			2,314,562			7,744,013			7,026,187

Operating expenses
Electric fuel and purchased power		1,110,781			982,103			3,085,347			2,703,952
Cost of natural gas sold and transported		66,571			71,638			774,647			809,791
Cost of sales — other		8,848			4,915			21,244			14,268
Other operating and maintenance expenses		509,634			466,465			1,507,247			1,410,760
Conservation and demand side management program expenses		60,861			47,157			174,451			133,793
Depreciation and amortization		221,671			198,222			639,303			609,285
Taxes (other than income taxes)		81,791			78,914			244,175			229,025
Total operating expenses		2,060,157			1,849,414			6,446,414			5,910,874

Operating income		568,630			465,148			1,297,599			1,115,313

Other income (expense), net		27,450			(977	)		30,134			4,394
Equity earnings of unconsolidated subsidiaries		7,670			4,363			22,433			10,760
Allowance for funds used during construction — equity		13,464			18,618			39,750			55,565

Interest charges and financing costs
Interest charges — includes other financing costs of $5,229, $5,103, $15,386 and $15,255, respectively		144,849			139,347			430,134			420,447
Allowance for funds used during construction — debt		(6,323	)		(9,598	)		(20,635	)		(29,671	)
Total interest charges and financing costs		138,526			129,749			409,499			390,776

Income from continuing operations before income taxes		478,688			357,403			980,417			795,256
Income taxes		166,200			135,610			364,964			280,581
Income from continuing operations		312,488			221,793			615,453			514,675
Income (loss) from discontinued operations, net of tax		(182	)		(965	)		3,747			(2,673	)
Net income		312,306			220,828			619,200			512,002
Dividend requirements on preferred stock		1,060			1,060			3,180			3,180
Earnings available to common shareholders	$	311,246		$	219,768		$	616,020		$	508,822

Weighted average common shares outstanding:
Basic		460,471			456,769			459,816			456,095
Diluted		462,019			457,453			460,722			456,729

Earnings per average common share — basic:
Income from continuing operations	$	0.68		$	0.48		$	1.33		$	1.12
Income from discontinued operations		-			-			0.01			-
Earnings per share	$	0.68		$	0.48		$	1.34		$	1.12

Earnings per average common share — diluted:
Income from continuing operations	$	0.67		$	0.48		$	1.33		$	1.11
Income from discontinued operations		-			-			0.01			-
Earnings per share	$	0.67		$	0.48		$	1.34		$	1.11

Cash dividends declared per common share	$	0.25		$	0.25		$	0.75		$	0.73

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands of dollars)

	Nine Months Ended Sept. 30,
	2010			2009

Operating activities
Net income	$	619,200		$	512,002
Remove (income) loss from discontinued operations		(3,747	)		2,673
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		648,089			622,563
Conservation and demand side management program expenses		18,694			21,661
Nuclear fuel amortization		78,150			59,520
Deferred income taxes		299,572			304,707
Amortization of investment tax credits		(4,782	)		(5,213	)
Allowance for equity funds used during construction		(39,750	)		(55,565	)
Equity earnings of unconsolidated subsidiaries		(22,433	)		(10,760	)
Dividends from unconsolidated subsidiaries		23,821			20,999
Share-based compensation expense		27,272			13,252
Net realized and unrealized hedging and derivative transactions		(61,136	)		46,298
Changes in operating assets and liabilities:
Accounts receivable		31,670			265,655
Accrued unbilled revenues		159,769			272,574
Inventories		(25,520	)		111,780
Recoverable purchased natural gas and electric energy costs		28,770			(30,792	)
Other current assets		17,635			(72,817	)
Accounts payable		(282,950	)		(286,019	)
Net regulatory assets and liabilities		56,358			20,422
Other current liabilities		(26,116	)		7,347
Change in other noncurrent assets		(4,184	)		(2,014	)
Change in other noncurrent liabilities		(36,634	)		(172,291	)
Operating cash flows provided by (used in) discontinued operations		19,981			(17,166	)
Net cash provided by operating activities		1,521,729			1,628,816

Investing activities
Utility capital/construction expenditures		(1,561,987	)		(1,310,686	)
Allowance for equity funds used during construction		39,750			55,565
Purchase of investments in external decommissioning fund		(3,309,093	)		(1,278,554	)
Proceeds from the sale of investments in external decommissioning fund		3,314,356			1,276,417
Investment in WYCO Development LLC		(6,119	)		(38,936	)
Change in restricted cash		91			(1,389	)
Other investments		2,044			3,472
Net cash used in investing activities		(1,520,958	)		(1,294,111	)

Financing activities
Proceeds from (repayment of) short-term borrowings, net		(419,000	)		38,750
Proceeds from issuance of long-term debt		1,038,368			394,762
Repayment of long-term debt, including reacquisition premiums		(200,452	)		(620,074	)
Proceeds from issuance of common stock		5,869			4,174
Dividends paid		(322,187	)		(309,320	)
Net cash provided by (used in) financing activities		102,598			(491,708	)

Net increase (decrease) in cash and cash equivalents		103,369			(157,003	)
Net increase (decrease) in cash and cash equivalents — discontinued operations		2,297			(1,989	)
Cash and cash equivalents at beginning of period		107,789			249,198
Cash and cash equivalents at end of period	$	213,455		$	90,206
Supplemental disclosure of cash flow information:
Cash paid for interest, net of amounts capitalized	$	(389,719	)	$	(400,511	)
Cash (paid) received for income taxes, net		(17,410	)		21,857
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	62,663		$	33,116
Supplemental disclosure of non-cash financing transactions:
Issuance of common stock for reinvested dividends and 401(k) plans	$	48,685		$	44,668

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands of dollars)

	Sept. 30, 2010		Dec. 31, 2009
Assets
Current assets
Cash and cash equivalents	$	213,455	$	107,789
Accounts receivable, net		703,960		729,409
Accrued unbilled revenues		534,280		694,049
Inventories		591,725		566,205
Recoverable purchased natural gas and electric energy costs		27,974		56,744
Derivative instruments valuation		65,573		97,700
Prepayments and other		296,097		359,560
Current assets related to discontinued operations		96,449		151,955
Total current assets		2,529,513		2,763,411

Property, plant and equipment, net		19,444,841		18,508,296

Other assets
Nuclear decommissioning fund and other investments		1,443,300		1,381,791
Regulatory assets		2,324,744		2,287,636
Derivative instruments valuation		261,748		289,530
Other		162,473		140,367
Noncurrent assets related to discontinued operations		134,847		117,397
Total other assets		4,327,112		4,216,721
Total assets	$	26,301,466	$	25,488,428

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	414,443	$	543,814
Short-term debt		40,000		459,000
Accounts payable		794,381		1,083,127
Taxes accrued		224,483		232,964
Accrued interest		161,553		157,253
Dividends payable		117,236		113,147
Derivative instruments valuation		80,929		46,554
Other		357,274		350,318
Current liabilities related to discontinued operations		9,185		29,080
Total current liabilities		2,199,484		3,015,257

Deferred credits and other liabilities
Deferred income taxes		3,616,378		3,336,354
Deferred investment tax credits		94,508		99,290
Regulatory liabilities		1,236,097		1,222,833
Asset retirement obligations		920,129		881,479
Derivative instruments valuation		299,279		307,770
Customer advances		274,310		295,470
Pension and employee benefit obligations		830,286		838,067
Other		251,819		211,666
Noncurrent liabilities related to discontinued operations		3,760		3,389
Total deferred credits and other liabilities		7,526,566		7,196,318

Commitments and contingent liabilities
Capitalization
Long-term debt		8,864,759		7,888,628
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: Sept. 30, 2010 – 460,104,538; Dec. 31, 2009 – 457,509,263		7,605,677		7,283,245
Total liabilities and equity	$	26,301,466	$	25,488,428

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Common Stock Issued						Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stockholders' Equity
	Shares		Par Value		Additional Paid In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stockholders' Equity
Three Months Ended Sept. 30, 2010 and 2009
Balance at June 30, 2009		455,717	$	1,139,292	$	4,727,380	$	1,256,405		$	(49,354	)	$	7,073,723
Net income								220,828						220,828
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $260											365			365
Net derivative instrument fair value changes during the period, net of tax of $(3,876)											(5,557	)		(5,557	)
Unrealized gain - marketable securities, net of tax of $62											90			90
Comprehensive income for the period														215,726
Dividends declared:
Cumulative preferred stock								(1,060	)					(1,060	)
Common stock								(112,255	)					(112,255	)
Issuances of common stock		534		1,337		7,485								8,822
Share-based compensation						6,224								6,224
Balance at Sept. 30, 2009		456,251	$	1,140,629	$	4,741,089	$	1,363,918		$	(54,456	)	$	7,191,180

Balance at June 30, 2010		459,627	$	1,149,069	$	4,800,841	$	1,493,997		$	(52,085	)	$	7,391,822
Net income								312,306						312,306
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $236											510			510
Net derivative instrument fair value changes during the period, net of tax of $554											784			784
Unrealized gain - marketable securities, net of tax of $37											54			54
Comprehensive income for the period														313,654
Dividends declared:
Cumulative preferred stock								(1,060	)					(1,060	)
Common stock								(116,754	)					(116,754	)
Issuances of common stock		478		1,192		7,805								8,997
Share-based compensation						9,018								9,018
Balance at Sept. 30, 2010		460,105	$	1,150,261	$	4,817,664	$	1,688,489		$	(50,737	)	$	7,605,677

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Common Stock Issued						Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stockholders' Equity
	Shares		Par Value		Additional Paid In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stockholders' Equity

Nine Months Ended Sept. 30, 2010 and 2009
Balance at Dec 31, 2008		453,792	$	1,134,480	$	4,695,019	$	1,187,911		$	(53,669	)	$	6,963,741
Net income								512,002						512,002
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $769											1,106			1,106
Net derivative instrument fair value changes during the period, net of tax of $(1,736)											(2,226	)		(2,226	)
Unrealized gain - marketable securities, net of tax of $230											333			333
Comprehensive income for the period														511,215
Dividends declared:
Cumulative preferred stock								(3,180	)					(3,180	)
Common stock								(332,815	)					(332,815	)
Issuances of common stock		2,459		6,149		25,550								31,699
Share-based compensation						20,520								20,520
Balance at Sept. 30, 2009		456,251	$	1,140,629	$	4,741,089	$	1,363,918		$	(54,456	)	$	7,191,180

Balance at Dec. 31, 2009		457,509	$	1,143,773	$	4,769,980	$	1,419,201		$	(49,709	)	$	7,283,245
Net income								619,200						619,200
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $852											1,385			1,385
Net derivative instrument fair value changes during the period, net of tax of $(1,711)											(2,371	)		(2,371	)
Unrealized loss - marketable securities, net of tax of $(29)											(42	)		(42	)
Comprehensive income for the period														618,172
Dividends declared:
Cumulative preferred stock								(3,180	)					(3,180	)
Common stock								(346,732	)					(346,732	)
Issuances of common stock		2,596		6,488		23,437								29,925
Share-based compensation						24,247								24,247
Balance at Sept. 30, 2010		460,105	$	1,150,261	$	4,817,664	$	1,688,489		$	(50,737	)	$	7,605,677

See Notes to Consolidated Financial Statements

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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, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) as of Sept. 30, 2010 and Dec. 31, 2009; the results of its operations and changes in stockholders’ equity for the three and nine months ended Sept. 30, 2010 and 2009; and its cash flows for the nine months ended Sept. 30, 2010 and 2009. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2010 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2009 balance sheet information has been derived from the audited 2009 consolidated financial statements. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto included in the Xcel Energy Annual Report on Form 10-K for the year ended Dec. 31, 2009, filed with the SEC on Feb. 26, 2010. Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1.	Summary of Significant Accounting Policies

Except to the extent updated or described below, the significant accounting policies 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, 2009, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

Reclassifications — Conservation and demand side management program expenses for the nine months ended Sept. 30, 2009 were reclassified as a separate line item from depreciation and amortization expenses within the consolidated statements of cash flows. The reclassification did not have an impact on net cash provided by operating activities.

2.	Accounting Pronouncements

Recently Adopted

Consolidation of Variable Interest Entities — In June 2009, the Financial Accounting Standards Board (FASB) issued new guidance on consolidation of variable interest entities. The guidance affects various elements of consolidation, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary. These updates to the FASB Accounting Standards Codification (ASC or Codification) were effective for interim and annual periods beginning after Nov. 15, 2009. Xcel Energy implemented the guidance on Jan. 1, 2010, and the implementation did not have a material impact on its consolidated financial statements. For further information and required disclosures regarding variable interest entities, see Note 7 to the consolidated financial statements.

Fair Value Measurement Disclosures — In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements (Accounting Standards Update (ASU) No. 2010-06), which updates the Codification to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for fair value measurements, transfers between levels of the fair value hierarchy, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the Codification contained in ASU No. 2010-06 were effective for interim and annual periods beginning after Dec. 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after Dec. 15, 2010. Xcel Energy implemented the portions of the guidance required on Jan. 1, 2010, and the implementation did not have a material impact on its consolidated financial statements. For further information and required disclosures, see Note 10 to the consolidated financial statements.

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3.	Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2010			Dec. 31, 2009
Accounts receivable, net
Accounts receivable	$	755,725		$	785,512
Less allowance for bad debts		(51,765	)		(56,103	)
	$	703,960		$	729,409
Inventories
Materials and supplies	$	186,199		$	172,993
Fuel		213,222			221,457
Natural gas		192,304			171,755
	$	591,725		$	566,205
Property, plant and equipment, net
Electric plant	$	23,923,771		$	22,589,071
Natural gas plant		3,367,303			3,269,934
Common and other property		1,512,255			1,492,463
Construction work in progress		1,667,407			1,769,545
Total property, plant and equipment		30,470,736			29,121,013
Less accumulated depreciation		(11,310,973	)		(10,914,509	)
Nuclear fuel		1,798,905			1,737,469
Less accumulated amortization		(1,513,827	)		(1,435,677	)
	$	19,444,841		$	18,508,296

4.	Discontinued Operations

Results of operations for divested businesses are reported, for all periods presented, as discontinued operations. The majority of current and noncurrent assets related to discontinued operations are deferred tax assets associated with temporary differences and net operating loss (NOL) and tax credit carryforwards that will be deductible in future years.

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

(Thousands of Dollars)	Sept. 30, 2010		Dec. 31, 2009
Cash	$	10,156	$	7,859
Deferred income tax benefits		59,993		106,770
Other current assets		26,300		37,326
Current assets related to discontinued operations	$	96,449	$	151,955

Deferred income tax benefits	$	116,826	$	95,424
Other noncurrent assets		18,021		21,973
Noncurrent assets related to discontinued operations	$	134,847	$	117,397

Accounts payable	$	272	$	445
Other current liabilities		8,913		28,635
Current liabilities related to discontinued operations	$	9,185	$	29,080

Noncurrent liabilities related to discontinued operations	$	3,760	$	3,389

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5.	Income Taxes

Corporate Owned Life Insurance (COLI) — In 2007, Xcel Energy and the U.S. government settled an ongoing dispute regarding PSCo’s right to deduct interest expense on policy loans related to its COLI program that insured lives of certain PSCo employees. These COLI policies were owned and managed by P.S.R. Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo. Xcel Energy paid the U.S. government a total of $64.4 million in settlement of the U.S. government’s claims for tax, penalty, and interest for tax years 1993 through 2007. Xcel Energy surrendered the policies to its insurer on Oct. 31, 2007, without recognizing a taxable gain. As a result of the settlement, the lawsuit filed by Xcel Energy in the United States District Court has been dismissed and the Tax Court proceedings are in the process of being dismissed.

As part of the Tax Court proceedings, during the first quarter of 2010, Xcel Energy and the Internal Revenue Service (IRS) reached an agreement in principle after a comprehensive financial reconciliation of Xcel Energy’s statement of account, dating back to tax year 1993. Upon completion of this review, PSRI recorded a net non-recurring tax and interest charge of approximately $10 million (including $7.7 million tax expense and $2.3 million interest expense, net of tax), during the first quarter of 2010. During the third quarter of 2010, Xcel Energy and the IRS came to final agreement on the applicable interest netting computations related to these tax years. Accordingly, PSRI recorded a reduction to expense of $0.6 million, net of tax, during the third quarter of 2010. Xcel Energy anticipates that the Tax Court proceedings will be dismissed in the fourth quarter of 2010.

In July 2010, Xcel Energy, PSCo and PSRI entered into a settlement agreement with Provident Life & Accident Insurance Company (Provident) related to all claims asserted by Xcel Energy, PSCo and PSRI against Provident in a lawsuit associated with the discontinued COLI program. Under the terms of the settlement, Xcel Energy, PSCo and PSRI were paid $25 million by Provident and Reassure America Life Insurance Company in the third quarter of 2010. The $25 million proceeds are not subject to income taxes.

Medicare Part D Subsidy Reimbursements — In March 2010, the Patient Protection and Affordable Care Act was signed into law. The law includes provisions to generate tax revenue to help offset the cost of the new legislation. One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013. Based on this provision, Xcel Energy is subject to additional taxes and is required to reverse previously recorded tax benefits in the period of enactment. Xcel Energy expensed approximately $17 million of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010. Xcel Energy does not expect the $17 million of additional tax expense to recur in future periods. The 2010 effective tax rate (ETR) will increase due to additional tax expense of approximately $4 million associated with current year retiree health care accruals.

Federal Audit — Xcel Energy files a consolidated federal income tax return. During the first quarter of 2010, the IRS completed an examination of Xcel Energy’s federal income tax returns of tax years 2006 and 2007. The IRS did not propose any material adjustments for those tax years. The statute of limitations applicable to Xcel Energy’s 2006 federal income tax return expired in August 2010. The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return expires in September 2011. The IRS commenced an examination of tax years 2008 and 2009 in the third quarter of 2010. As of Sept. 30, 2010, the IRS had not proposed any material adjustments to tax years 2008 and 2009.

State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. As of Sept. 30, 2010, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions are as follows:

State		Year
Colorado		2004
Minnesota		2006
Texas		2005
Wisconsin		2005

In 2009, Xcel Energy received a request for information from the state of Minnesota relating to tax years 2002 through 2007 in order to determine whether to undertake an audit of those years. During the second quarter of 2010, the state of Minnesota informed Xcel Energy that the state’s request for information relating to tax years 2002 through 2007 had been fulfilled. The state indicated that it does not intend to perform audit procedures on these years at this time. Also, during the second quarter of 2010, the state of Texas completed its audit of tax years 2006 and 2007. No change in tax liability was proposed. There currently are no state income tax audits in progress.

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Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefit related to continuing operations is as follows:

(Millions of Dollars)	Sept. 30, 2010		Dec. 31, 2009
Unrecognized tax benefit - Permanent tax positions	$	3.7	$	4.0
Unrecognized tax benefit - Temporary tax positions		30.6		19.7
Unrecognized tax benefit balance	$	34.3	$	23.7

A reconciliation of the amount of unrecognized tax benefit related to discontinued operations is as follows:

(Millions of Dollars)	Sept. 30, 2010		Dec. 31, 2009
Unrecognized tax benefit - Permanent tax positions	$	0.3	$	6.6
Unrecognized tax benefit - Temporary tax positions		-		-
Unrecognized tax benefit balance	$	0.3	$	6.6

The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards that relate to continuing operations and discontinued operations were as follows:

(Millions of Dollars)	Sept. 30, 2010			Dec. 31, 2009
Continuing operations	$	(19.5	)	$	(8.9	)
Discontinued operations		(13.4	)		(20.4	)

The increase in the unrecognized tax benefit balance reported in continuing operations of $7.7 million from June 30, 2010 to Sept. 30, 2010 and $10.6 million from Dec. 31, 2009 to Sept. 30, 2010 was due primarily to the addition of uncertain tax positions related to current and prior years’ activity. Xcel Energy’s amount of unrecognized tax benefits related to continuing operations could significantly change in the next 12 months as the IRS audit progresses and state audits resume. At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

There was no change in the unrecognized tax benefit balance related to discontinued operations from June 30, 2010 to Sept. 30, 2010. The decrease in the unrecognized tax benefit balance related to discontinued operations of $6.3 million from Dec. 31, 2009 to Sept. 30, 2010 was due to a clarification of tax law in a court ruling issued to an unrelated taxpayer, coupled with the completion of the state of Minnesota review of tax years 2002 through 2007. Xcel Energy’s remaining amount of unrecognized tax benefits related to discontinued operations is not expected to change significantly in the next 12 months.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits related to continuing operations is as follows:

(Millions of Dollars)	2010			2009
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(0.4	)	$	(1.9	)
Interest expense related to unrecognized tax benefits for the three months ended March 31		(0.1	)		(0.3	)
Interest expense related to unrecognized tax benefits for the three months ended June 30		(0.3	)		-
Interest expense related to unrecognized tax benefits for the three months ended Sept. 30		-			(0.7	)
Payable for interest related to unrecognized tax benefits at Sept. 30	$	(0.8	)	$	(2.9	)

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A reconciliation of the beginning and ending amount of the receivable for interest related to unrecognized tax benefits related to discontinued operations is as follows:

(Millions of Dollars)	2010		2009
Receivable for interest related to unrecognized tax benefits at Jan. 1	$	0.2	$	1.5
Interest income related to unrecognized tax benefits for the three months ended March 31		0.1		0.2
Interest income related to unrecognized tax benefits for the three months ended June 30		0.2		0.1
Interest income related to unrecognized tax benefits for the three months ended Sept. 30		0.1		0.6
Receivable for interest related to unrecognized tax benefits at Sept. 30	$	0.6	$	2.4

No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2010 or Dec. 31, 2009.

6.	Rate Matters

Except to the extent noted below, the circumstances set forth in Note 16 to the consolidated financial statements included in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2009 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)

Base Rate

NSP-Minnesota Gas Rate Case — In November 2009, NSP-Minnesota filed a request with the MPUC to increase Minnesota natural gas rates by $16.2 million for 2010, based on a return on equity (ROE) of 11 percent, an equity ratio of 52.46 percent and a rate base of $441 million. The overall request seeks an additional $3.5 million, effective Jan. 1, 2011, for recovery of pension funding costs necessary to comply with federal law. In December 2009, the MPUC approved an interim rate increase of $11.1 million, subject to refund. Interim rates went into effect on Jan. 11, 2010.

NSP-Minnesota made several adjustments and is currently seeking an increase of $10.0 million based on a 10.6 percent ROE. The Office of Energy Security (OES) revised its case and is now recommending an increase of approximately $7.5 million based on a 10.09 percent ROE. NSP-Minnesota and the Minnesota Office of Attorney General (OAG) agreed on treatment of pension issues, for future rate proceedings, and NSP-Minnesota is no longer seeking a 2011 step-in of pension expense. The OAG continued to recommend further adjustments in bad debt expense, distribution operating and maintenance (O&M) expenses and the cost of debt.

In October 2010, the administrative law judge (ALJ) issued his report and recommended a rate increase of approximately $8 million, based on a 10.09 percent ROE. A decision from the MPUC is anticipated late in the fourth quarter of 2010.

Electric, Purchased Gas and Resource Adjustment Clauses

Transmission Cost Recovery (TCR) Rider — The MPUC has approved a TCR rider that allows annual adjustments to retail electric rates to provide recovery of certain incremental transmission investments between rate cases. In April 2010, the MPUC approved the 2010 TCR rider that will recover approximately $10.8 million in 2010. In October 2010, NSP-Minnesota filed its 2011 rider recovery request, seeking approval to recover approximately $12.9 million during 2011.

Renewable Energy Standard (RES) Rider — The MPUC has approved a RES rider to recover the costs for utility-owned projects implemented in compliance with the Minnesota RES. In April 2010, the MPUC approved the 2010 RES rider that resulted in $38.4 million in revenue recovery beginning May 1, 2010. In October 2010, NSP-Minnesota filed its 2011 rider recovery request, seeking approval to recover approximately $67.8 million during 2011.

State Energy Policy (SEP) Rider — In March 2010, NSP-Minnesota filed a request to recover approximately $2.5 million of Minnesota electric retail revenue requirements and $0.7 million of natural gas retail revenue requirements during the July 2010-June 2011 timeframe related to SEP mandates. In September 2010, the MPUC issued an order approving NSP-Minnesota’s petition with a rate implementation date of Oct. 1, 2010.

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Metropolitan Emissions Reduction Project (MERP) Rider — In December 2009, the MPUC authorized NSP-Minnesota to recover the 2010 revenue requirements related to environmental improvement projects amounting to approximately $116.7 million in 2010 through the MERP rider. In October 2010, NSP-Minnesota filed a request to recover approximately $111.4 million during 2011. Final MPUC action is pending.

Renewable Development Fund (RDF) Rider — The MPUC has approved an RDF rider that allows annual adjustments to retail electric rates to provide for the recovery of RDF program and project expenses. In June 2010, the MPUC authorized NSP-Minnesota to recover $22.9 million in RDF expenses in 2010 through the RDF rider. The primary components of RDF costs are legislatively mandated expenses such as renewable energy production incentive payments, RDF grant project payments, and RDF program administrative costs. In October 2010, NSP-Minnesota filed its annual request to recover $19.2 million in expenses for 2011. Final MPUC action is pending.

Annual Automatic Adjustment Report for 2008/2009 — In September 2009, NSP-Minnesota filed its annual electric and natural gas automatic adjustment reports for July 1, 2008 through June 30, 2009. During that time period, $803.6 million in fuel and purchased energy costs were recovered from Minnesota electric customers through the fuel clause adjustment (FCA). In addition, approximately $499.4 million of purchased natural gas and transportation costs were recovered from Minnesota natural gas customers through the purchased gas adjustment (PGA). In June 2010, the OES filed comments recommending approval of the 2008/2009 natural gas automatic adjustment report. FCA and PGA recovery remains provisional and potentially subject to refund until the MPUC issues an order approving the automatic adjustment report for the period. Final MPUC action is pending.

Annual Automatic Adjustment Report for 2009/2010 — In September 2010, NSP-Minnesota filed its annual electric and natural gas automatic adjustment reports for July 1, 2009 through June 30, 2010. During that time period, $749.5 million in fuel and purchased energy costs were recovered from Minnesota electric customers through the FCA. In addition, approximately $354.5 million of purchased natural gas and transportation costs were recovered from Minnesota natural gas customers through the PGA. FCA and PGA recovery remains provisional and potentially subject to refund until the MPUC issues an order approving the automatic adjustment report for the period. Final MPUC action is pending.

NSP-Wisconsin

Pending and Recently Concluded Regulatory Proceedings — Public Service Commission of Wisconsin (PSCW)

2010 Electric Fuel Cost Recovery — Pursuant to Wisconsin fuel rules, in May 2010, the PSCW set NSP-Wisconsin’s electric rates subject to refund with interest at 10.40 percent, pending a full review of 2010 fuel costs. The PSCW has not begun its review of 2010 fuel costs. NSP-Wisconsin’s fuel and purchased power costs through September 2010 were approximately $2.0 million, or 1.5 percent, lower than authorized in the 2010 electric rate case, which is within the cumulative variance range for the monitored fuel costs established by the PSCW. However, based on forecasts for the remainder of 2010, NSP-Wisconsin could exceed the 2.0 percent variance range and be required to provide a refund to customers. NSP-Wisconsin has established a liability of $1.4 million for such amounts subject to refund collected through Sept. 30, 2010.

2010 Electric Rate Case Reopener — In August 2010, NSP-Wisconsin filed a request with the PSCW to reopen the 2010 rate case and increase retail electric rates for 2011 by $29.1 million, or 5.4 percent, based on a forecast 2011 test year. The requested increase in electric rates is primarily related to production and transmission fixed charges, specifically new investment in cleaner sources of energy and transmission lines to help reliably meet customers' electric needs as well as forecast cost increases for fuel and purchased power. Partially offsetting these increased costs is a refund of the Wisconsin customers’ share of excess funds in the Monticello nuclear generating plant external decommissioning fund. No changes are requested to the capital structure or ROE authorized by the PSCW in the 2010 base rate case.

The major cost components of the requested increase are summarized below:

(Millions of Dollars)	Request
Production and transmission fixed charges	$	19.3
Fuel and purchased power		12.1
Other		3.5
Monticello nuclear decommissioning fund refund		(5.8	)
Total	$	29.1

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The PSCW held a pre-hearing conference in September 2010 and established the following procedural schedule:

Staff and intervenor direct testimony due Nov. 5, 2010;

Rebuttal testimony due Nov. 12, 2010;

Surrebuttal testimony due Nov. 16, 2010;

Technical and public hearings scheduled for Nov. 17, 2010; and

Initial brief due Dec. 6, 2010.

NSP-Wisconsin has requested that the PSCW approve this application to allow new rates to be effective Jan. 1, 2011.

PSCo

Pending and Recently Concluded Regulatory Proceedings — Colorado Public Utilities Commission (CPUC)

Base Rate

2010 Electric Rate Case — In December 2009, the CPUC approved a rate increase of approximately $128.3 million; however, due to the delay in Comanche Unit 3 coming online, the CPUC approved PSCo’s proposal to phase in the approved electric rate increase to reflect the actual cost of service. Under the plan, the following increases have or will be implemented:

A rate increase of $67 million was implemented on Jan. 1, 2010 because of the delay of the in-service date of Comanche Unit 3;

Base rates were increased to recover $123 million annually, on May 14, 2010 when Comanche Unit 3 went into service, including an additional $2 million of recovery for long-term debt interest in the working capital calculation granted under reconsideration; and

Base rates will increase to recover approximately $130 million annually on Jan. 1, 2011 to reflect 2011 property taxes.

A second phase of the rate case addressed changes to rate design. The new rates, approved by the CPUC, went into effect on June 1, 2010. In this phase of the proceeding, the CPUC approved tiered summer rates for residential customers and seasonally differentiated rates for other customer classes, which will impact the timing of revenue collection, as compared to the previous rate design, depending on customer response. Seasonal rates are designed to be revenue neutral on an annual basis. However, the quarterly pattern of revenue collection is expected to be different than in the past as seasonal rates are higher in the summer months and lower throughout the remainder of the year.

Electric, Purchased Gas and Resource Adjustment Clauses

Transmission Cost Adjustment (TCA) Rider — In April 2010, PSCo filed a TCA rider, to adjust the amounts recovered in the rider based on the outcome of the 2010 rate case. The filing reduced rates by $2.3 million, effective June 1, 2010. The new TCA rider reflects actual 13-month average transmission plant in service and year-end transmission construction work in progress (CWIP) account balances for 2009, as compared to the amount of transmission costs included in PSCo's last rate case.

Renewable Energy Credit (REC) Sharing Settlement — In August 2009, PSCo filed an application seeking approval of treatment of margins associated with certain sales of Colorado RECs bundled with energy into California. In January 2010, PSCo, the OCC, the CPUC staff, the Colorado governor’s energy office and Western Resource Advocates entered into a unanimous settlement in this case. The settlement establishes a pilot program and defines certain margin splits during this pilot period. The settlement provides that margins would be shared based on the following allocations:

Margin	Customers			PSCo			Carbon Offsets
Less that $10 million		50	%		40	%		10	%
$10 million to $30 million		55			35			10
Greater than $30 million		60			30			10

Amounts designated as carbon offsets are recorded as a regulatory liability until carbon offset-related expenditures are incurred. Carbon offsets are capped at $10 million, with the remaining 10 percent going to customers after the cap is reached. The unanimous settlement also clarified that margins associated with RECs bundled with Colorado energy would be shared 20 percent to PSCo and 80 percent to customers and margins associated with sales of stand-alone RECs without energy would be credited 100 percent to customers. The CPUC approved the settlement in a written order in May 2010.

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Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Wholesale Rate Case — In 2009, PSCo filed a request with the FERC to increase electric rates to its firm wholesale customers by $30.7 million based on a 12.5 percent ROE, a 58 percent equity ratio and a rate base of $315 million. During the summer of 2010, PSCo filed blackbox settlements with all of its wholesale customers. The settlements provided for new rates reflecting an electric rate increase of approximately $21.0 million for these customers effective in July 2010. In addition, on Jan. 1, 2011, an additional step rate increase of $1.0 million will be implemented for property taxes associated with Comanche Unit 3. The terms of the settlements provide for lower depreciation expense than requested and for certain capacity costs to be recovered through the fuel clause until those contracts expire. The FERC approved the settlements on Oct. 21, 2010.

SPS

Pending and Recently Concluded Regulatory Proceedings — Public Utility Commission of Texas (PUCT)

Texas Retail Base Rate Case — In May 2010, SPS filed an electric rate case in Texas rate case seeking an annual base rate increase of approximately $62 million. On a net basis, the request seeks to increase customer bills by approximately $53.4 million, or 7 percent. The rate filing is based on a 2009 test year adjusted for known and measurable changes, a requested ROE of 11.35 percent, an electric rate base of $1.031 billion and an equity ratio of 51.0 percent. The following table summarizes the request:

(Millions of Dollars)	Request
Proposed base rate increase	$	62.0
Franchise fee cost recovery		8.7
Nitrogen oxide emission allowances		0.8
Purchased capacity recovery factor		(13.5	)
Transmission cost recovery factor		(4.6	)
Adjusted rate increase	$	53.4

The filing with the PUCT also includes a request to reconcile SPS’ fuel and purchased power costs for calendar years 2008 and 2009. As of Dec. 31, 2009, SPS had a fuel cost under-recovery of approximately $3.3 million.

In September 2010, SPS filed an agreement with the intervening parties to abate, or suspend, the procedural schedule for a 90-day extension in this case. The extension allows time for SPS to receive regulatory approval of the sale of distribution assets to the city of Lubbock, Texas (Lubbock), noted below, and to allow the intervening parties to ascertain the financial impact of the sale. SPS made a filing on Oct. 19, 2010 showing the on-going savings related to the Lubbock sale. As part of the agreement to abate the procedural schedule, the parties agreed that the effective date of implementation of SPS’ new rates is expected to be Feb. 16, 2011. This will be accomplished either by establishing interim rates effective on Feb. 16, 2011; or by making the final rates effective retroactive back to Feb. 16, 2011 from the date SPS implements final rates, after the PUCT issues its final order.

The revised the procedural schedule is as follows:

Intervenor direct testimony due Jan. 18, 2011;

PUCT staff direct testimony due Jan. 25, 2011;

PUCT staff and intervenor cross rebuttal testimony due Feb. 1, 2011;

SPS rebuttal testimony due Feb. 8, 2011; and

Hearings on Feb. 21, 2011 through March 11, 2011.

Lubbock Electric Distribution Assets — In November 2009, SPS entered into an agreement with Lubbock, in which SPS will sell its electric distribution system assets in Lubbock to Lubbock Power and Light for approximately $87 million. As part of this transaction, SPS will continue to provide the wholesale power to meet the electric load for the customers that SPS currently serves. The wholesale power agreements provide for formula rates that change annually based on the actual cost of service. The formula rate with West Texas Municipal Power Agency (WTMPA) reflects an initial 10.5 percent ROE. All or portions of this transaction are subject to review and approval by the PUCT, the New Mexico Public Regulation Commission (NMPRC) and the FERC. It is anticipated that any resulting gain on the sale of assets will be shared with retail customers in Texas, as determined in the Texas retail base rate case discussed above.

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The FERC accepted the amended WTMPA full-requirements contract in February 2010. SPS filed its application before the PUCT in January 2010 for the approvals related to the sale of distribution assets to Lubbock. In June 2010, an uncontested settlement was filed resolving all issues in the Texas proceeding relating to the transaction. The PUCT approved the uncontested settlement in August 2010.

In June 2010, SPS filed its application in New Mexico for approval of the transaction. Settlement has been reached with all the parties. A decision and order approving the settlement was issued by the NMPRC in October 2010. The transaction is expected to close in late October or early November 2010.

Pending and Recently Concluded Regulatory Proceedings — FERC

Transmission Formula Rate Case — In December 2007, SPS filed a transmission formula rate with the FERC. The FERC accepted the filing, initiated settlement and hearing procedures, and interim rates went into effect on July 6, 2008, subject to refund. An uncontested, partial settlement was reached in September 2009. The settlement, including an 11.27 percent ROE and a future test year, was approved by the FERC in December 2009. The remaining cost allocation of the radial transmission lines issue was resolved by a settlement filed in June 2010, where the expense of the Cap Rock Energy Corporation (Cap Rock) 230 kilovolt (KV) lines was assigned to overall transmission facilities and not directly assigned to Cap Rock. This is subject to a future change in configuration of the 230 KV lines. The radial line settlement was approved by the FERC in August 2010.

Wholesale Rate Complaints — In November 2004, Golden Spread Electric, Lyntegar Electric, Farmer’s Electric, Lea County Electric, Central Valley Electric and Roosevelt County Electric, all wholesale cooperative customers of SPS, filed a rate complaint with the FERC alleging that SPS’ rates for wholesale service were excessive and that SPS had incorrectly calculated monthly fuel cost adjustment charges to such customers (the complaint). Cap Rock, another full-requirements customer of SPS, Public Service Company of New Mexico (PNM) and Occidental Permian Ltd. and Occidental Power Marketing, L.P. (Occidental), SPS’ largest retail customer, intervened in the proceeding.

In April 2008, the FERC issued its order on the complaint applied to the remaining non-settling parties. In July 2008, SPS submitted its compliance report to the FERC and calculated the base rate refund for the 18-month period to be $6.1 million and the fuel refund to be $4.4 million. Several wholesale customers protested these calculations. As of Sept. 30, 2010, SPS has accrued an amount it believes is sufficient to cover the estimated refund obligation related to these complaints. The status of various settlements and the applicable regulatory approvals are discussed below. At this time, PNM, which filed a separate complaint, is the only party that has not settled.

Golden Spread Complaint Settlement — SPS reached a settlement with Golden Spread (which included Lyntegar Electric) and Occidental in December 2007 regarding base rate and fuel issues raised in the complaint described above as well as a subsequent rate proceeding. The FERC approved the settlement in April 2008. The PUCT and NMPRC approvals were obtained in the first quarter of 2010 eliminating the potential contingent payments by SPS resulting from an adverse cost assignment decision or a failure to obtain state approvals.

New Mexico Cooperatives’ Complaint Settlement — In June 2010, the FERC approved the settlement with Farmers’ Electric Cooperative of New Mexico, Lea County Electric Cooperative, Central Valley Electric Cooperative and Roosevelt County Electric Cooperative, and Occidental. The settlement resolves all issues arising from the complaint docket and implements a replacement contract with a formula production rate at 10.5 percent ROE and extended the term of its requirements sale to the four wholesale customers.

The four wholesale customers must reduce their power purchases by 90 to 100 MW in 2012, and implement staged reductions in system average cost power purchases through the term of the agreement, which terminates in May 2026. The settlement made the replacement contract contingent on certain state approvals, which were obtained by SPS. In the event that all state regulatory approvals had not been received, the settlement included a one time contingent payment of $12 million by SPS to these wholesale customers.

These wholesale customers agreed to hold SPS harmless from any future adverse regulatory treatment regarding the proposed wholesale power sale. As a result of the FERC approval of the settlement and resolution of the complaint with the New Mexico cooperatives, SPS released previously established reserves of $11.5 million in the second quarter of 2010.

The New Mexico parties and NMPRC staff filed a stipulation to resolve the NMPRC proceeding. The NMPRC issued a final order approving the stipulation in August 2010. The PUCT approved the settlement replacement arrangement in September 2010.

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Cap Rock Complaint Settlement — In July 2010, SPS and Cap Rock filed a settlement agreement with the FERC. Subject to FERC approval of the settlement agreement, SPS will pay Cap Rock $1 million to resolve all remaining base rate and fuel claims against SPS. Cap Rock also agrees that its production base rates will be converted to a formula rate design. The complaint settlement agreement is still pending FERC approval.

7.	Commitments and Contingent Liabilities

Except to the extent noted below and in Note 6 to the consolidated financial statements in this Quarterly Report on Form 10-Q, the circumstances set forth in Notes 16, 17 and 18 to the consolidated financial statements included in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2009, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to Xcel Energy’s financial position.

Commitments

Variable Interest Entities — Effective Jan. 1, 2010, Xcel Energy adopted new guidance on consolidation of variable interest entities contained in ASC 810 Consolidation. The guidance requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary.

Purchased Power Agreements — The utility subsidiaries of Xcel Energy have entered into agreements with other utilities and energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance or during outages, and meet operating reserve obligations.

NSP-Minnesota, PSCo and SPS have various pay-for-performance contracts with expiration dates through the year 2034. In general, these contracts provide for energy payments based on actual power taken under the contracts as well as capacity payments. Capacity payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices; however, the effects of price adjustments are mitigated through purchased energy cost recovery mechanisms.

Xcel Energy purchases power from independent power producing entities that own natural gas or biomass fueled power plants. Under certain purchased power agreements with these entities, Xcel Energy is required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which Xcel Energy procures the natural gas required to produce the energy that Xcel Energy purchases. These purchased power agreements have been determined by Xcel Energy to create variable interests in the independent power producing entities; therefore, certain independent power producing entities are variable interest entities.

Xcel Energy is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future required to be provided other than contractual payments for energy and capacity set forth in purchased power agreements.

Xcel Energy has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, historical and estimated future fuel and electricity prices, and financing activities. Xcel Energy has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. As of Sept. 30, 2010 and Dec. 31, 2009, Xcel Energy had approximately 5,012 MW of capacity under long-term purchased power agreements with entities that have been determined to be variable interest entities.

Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk electric generating stations from TUCO, Inc. (TUCO) under contracts for those facilities that expire in 2016 and 2017, respectively. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.

No significant financial support has been, or is in the future, required to be provided to TUCO by SPS, other than contractual payments for delivered coal. However, the fuel contracts have been determined to create a variable interest in TUCO due to SPS’ reimbursement of certain fuel procurement costs, and therefore TUCO is a variable interest entity. SPS has concluded that it is not the primary beneficiary of TUCO because SPS does not have the power to direct the activities that most significantly impact TUCO’s economic performance.

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Low-Income Housing Limited Partnerships — Eloigne Company (Eloigne) and NSP-Wisconsin have entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. Xcel Energy has determined Eloigne and NSP-Wisconsin’s low-income housing limited partnerships to be variable interest entities primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not consistently align with the partners’ proportional equity ownership. These limited partnerships are designed to qualify for low-income housing tax credits, and Eloigne and NSP-Wisconsin generally receive a larger allocation of the tax credits than the general partners at inception of the arrangements. Xcel Energy has determined that Eloigne and NSP-Wisconsin have the power to direct the activities that most significantly impact these entities’ economic performance, and therefore Xcel Energy consolidates these limited partnerships in its consolidated financial statements.

Equity financing for these entities has been provided by Eloigne and NSP-Wisconsin and the general partner of each limited partnership, and Xcel Energy’s risk of loss is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is in the future, required to be provided to the limited partnerships by Eloigne or NSP-Wisconsin. Mortgage-backed debt typically comprises the majority of the financing at inception of each limited partnership and is paid over the life of the limited partnership arrangement. Obligations of the limited partnerships are generally secured by the low-income housing properties of each limited partnership, and the creditors of each limited partnership have no significant recourse to Xcel Energy or its subsidiaries. Likewise, the assets of the limited partnerships may only be used to settle obligations of the limited partnerships, and not those of Xcel Energy or its subsidiaries.

Amounts reflected in Xcel Energy’s consolidated balance sheets for the Eloigne and NSP-Wisconsin low-income housing limited partnerships include the following:

(Thousands of Dollars)	Sept. 30, 2010		Dec. 31, 2009
Current assets	$	3,527	$	3,674
Property, plant and equipment, net		100,144		103,552
Other noncurrent assets		8,355		7,577
Total assets	$	112,026	$	114,803

Current liabilities	$	11,832	$	12,315
Mortgages and other long-term debt payable		54,524		54,927
Other noncurrent liabilities		8,344		8,250
Total liabilities	$	74,700	$	75,492

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 believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, the subsidiary involved is pursuing, or intends to pursue, recovery from other potentially responsible parties (PRPs) and through the rate regulatory process. New and changing federal and state environmental mandates can also create added financial liabilities for Xcel Energy and its subsidiaries, which are normally recovered 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.

Site Remediation — Xcel Energy must pay all or a portion of the cost to remediate sites where past activities of its subsidiaries or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former manufactured gas plants (MGPs) operated by Xcel Energy subsidiaries, predecessors, or other entities; and third-party sites, such as landfills, for which Xcel Energy is alleged to be a PRP that sent hazardous materials and wastes. At Sept. 30, 2010 and Dec. 31, 2009, the liability for the cost of remediating these sites was estimated to be $101.9 million and $102.1 million, respectively, of which $5.3 million and $6.3 million, respectively, was considered to be a current liability.

Manufactured Gas Plant Sites

Ashland MGP Site — NSP-Wisconsin has been named a PRP for creosote and coal tar contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (Ashland site) includes property owned by NSP-Wisconsin, which was previously an MGP facility and two other properties: an adjacent city lakeshore park area, on which an unaffiliated third party previously operated a sawmill; and an area of Lake Superior’s Chequamegon Bay adjoining the park.

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In September 2002, the Ashland site was placed on the National Priorities List. In 2009, the Environmental Protection Agency (EPA) issued its proposed remedial action plan (PRAP). NSP-Wisconsin submitted comments to the EPA in response to the PRAP, and indicated that it had serious concerns about the cleanup approach proposed by the EPA. The EPA issued its Record of Decision (ROD) on Sept. 30, 2010, which documents the remedy that the EPA has selected for the cleanup of the site. The EPA has estimated the cost for its selected cleanup is between $84 million and $98 million. NSP-Wisconsin continues to have concerns over the cleanup approach selected by the EPA. It is anticipated that the EPA will issue special notice letters to several PRPs, including NSP-Wisconsin, by Dec. 1, 2010, and in those letters, the EPA will invite the PRPs to participate in negotiations with the EPA to conduct or pay for all, or a portion, of the future cleanup work at the site.

NSP-Wisconsin’s potential liability, the actual cost of remediating the Ashland site and the time frame over which the amounts may be paid out are not determinable until after the EPA issues special notice letters and engages in negotiations with the PRPs at the site. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site. NSP-Wisconsin has recorded a liability of $97.5 million based upon the remediation and design costs estimated by the ROD, together with estimated outside legal and consultant costs.

NSP-Wisconsin has deferred, as a regulatory asset, the costs accrued for the Ashland site based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site and has authorized recovery of similar remediation costs for other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin biennial retail rate case process. A final determination of the scope and cost of the remediation of the Ashland site is not currently expected until 2011.

In addition, in 2003, the Wisconsin Supreme Court rendered a ruling that reopens the possibility that NSP-Wisconsin may be able to recover a portion of the remediation costs from its insurance carriers. Any insurance proceeds received by NSP-Wisconsin will be credited to ratepayers.

In addition to potential liability for remediation, NSP-Wisconsin may also have potential liability for natural resource damages at the Ashland site. NSP-Wisconsin has recorded an estimate of its potential liability based upon its best estimate of potential exposure.

Third Party and Other Environmental Site Remediation

Asbestos Removal — Some of Xcel Energy’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. Xcel Energy has recorded an estimate for final removal of the asbestos as an asset retirement obligation (ARO). See additional discussion of AROs in Note 17 to the Xcel Energy Annual Report on Form 10-K for the year ended Dec. 31, 2009. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Other Environmental Requirements

EPA Greenhouse Gas (GHG) Rulemaking — In December 2009, in response to the U.S. Supreme Court’s decision in Massachusetts v. EPA, 549 U.S. 497 (2007), the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare and that emissions from motor vehicles contribute to the GHGs in the atmosphere. The EPA has promulgated permit requirements for GHGs for large new and modified stationary sources, such as power plants. These regulations will become applicable in 2011.

Clean Air Interstate Rule (CAIR) — In March 2005, the EPA issued the CAIR to further regulate sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions. The objective of CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Minnesota, Texas and Wisconsin, which are within Xcel Energy’s service territory. In 2008, the U.S. Court of Appeals for the District of Columbia vacated and remanded CAIR.

In July 2010, the EPA issued the proposed Clean Air Transport Rule (CATR), which would replace CAIR by requiring SO2 and NOx reductions in 31 states and the District of Columbia. The EPA is proposing to reduce these emissions through federal implementation plans for each affected state. The EPA's preferred approach would set emission limits for each state and allow limited interstate emissions trading. As proposed, CATR will impact Minnesota and Wisconsin for annual SO2 and NOx emissions, and Texas in the form of ozone season NOx emission allowances. Xcel Energy is analyzing the proposed rule to determine whether emission reductions are needed from facilities in these affected states. Until CATR becomes final, Xcel Energy will continue activities to support CAIR compliance.

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CAIR – SPS

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. The remaining scheduled capital investments for NOx controls in the SPS region are estimated at $16.4 million. For 2009, the NOx allowance compliance costs were $1.7 million. The estimated NOx allowance cost for 2010 is $0.5 million. Annual purchases of SO2 allowances are estimated up to $4.5 million each year, beginning in 2013, for phase I. If CATR is implemented as proposed then no SO2 allowances would be purchased since CATR replaces CAIR. Xcel Energy believes the cost of any required capital investment or allowance purchases will be recoverable from customers in rates.

CAIR – NSP-Wisconsin and NSP-Minnesota

For 2009, the NOx allowance costs for NSP-Wisconsin were $0.5 million. The estimated NOx allowance cost for 2010 is $0.2 million. Xcel Energy believes the cost of any required capital investment or allowance purchases will be recoverable from customers in rates. In November 2009, the EPA published a rule staying the effectiveness of CAIR in Minnesota effective in December 2009. Cost estimates are therefore not included at this time for NSP-Minnesota.

Clean Air Mercury Rule (CAMR) — In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants. In February 2008, the U.S. Court of Appeals for the District of Columbia vacated the CAMR, which impacted federal CAMR requirements, but not necessarily state-only mercury legislation and rules. The EPA has agreed to finalize Maximum Achievable Control Technology (MACT) emission standards for all hazardous air pollutants from electric utility steam generating units by November 2011 to replace the CAMR. Xcel Energy anticipates that the EPA will require affected facilities to demonstrate compliance within three to five years.

Colorado Mercury Regulation — Colorado’s mercury regulations require mercury emission controls capable of achieving 80 percent capture to be installed at the Pawnee Generating Station by 2012 and other specified units by 2014. The expected cost estimate for the Pawnee Generating Station is $2.3 million for capital costs with an annual estimate of $1.4 million for sorbent expense. PSCo has evaluated the Colorado mercury control requirements for its other units in Colorado and believes that, under the current regulations, no further controls will be required other than the planned controls at the Pawnee Generating Station.

Minnesota Mercury Legislation — In May 2006, the Minnesota legislature enacted the Mercury Emissions Reduction Act of 2006 (Act) providing a process for plans, implementation and cost recovery for utility efforts to curb mercury emissions at certain power plants. For NSP-Minnesota, the Act covers units at the A.S. King and Sherco generating facilities. NSP-Minnesota installed and is operating and maintaining continuous mercury emission monitoring systems at these generating facilities.

In November 2008, the MPUC approved and ordered the implementation of the Sherco Unit 3 and A.S. King mercury emission reduction plans. A sorbent injection control system was installed at Sherco Unit 3 in December 2009, with installation at A.S. King scheduled for December 2010. In November 2009, the MPUC authorized NSP-Minnesota to collect approximately $3.5 million from customers through a mercury rider in 2010.

In December 2009, NSP-Minnesota filed its mercury control plan at Sherco Units 1 and 2 with the MPUC and the Minnesota Pollution Control Agency (MPCA). In June 2010, the MPCA filed its comments on the Sherco Unit 1 and 2 mercury plan and believes the plan to be appropriate under the Act. The MPUC is expected to either approve or disapprove the plan by Dec. 15, 2010. Assuming that the plan is approved, NSP-Minnesota expects to file for recovery of the costs to implement the plan through the mercury cost recovery rider.

Regional Haze Rules — In June 2005, the EPA finalized amendments to its regional haze rules regarding provisions that require emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze. Xcel Energy generating facilities in several states will be subject to BART requirements. States are required to identify the facilities that will have to reduce SO2, NOx and particulate matter emissions under BART and then set BART emissions limits for those facilities.

PSCo

In May 2006, the Colorado Air Quality Control Commission promulgated BART regulations requiring certain major stationary sources to evaluate, install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal. The Colorado Air Pollution Control Division (CAPCD) is currently analyzing what types of NOx controls may be necessary to meet BART and reasonable progress goals for Colorado’s Class I areas. The CAPCD has indicated that it expects to submit a Regional Haze BART/Reasonable Further Progress state implementation plan (SIP) to the EPA in early 2011. PSCo anticipates that for those plants included in the Colorado Clean Air-Clean Jobs Act’s (CACJA) emission reduction plan, the plan will satisfy regional haze requirements. PSCo expects the cost of any required capital investment will be recoverable from customers. Emissions controls are expected to be installed between 2012 and 2017.

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In March 2010, two environmental groups petitioned the U.S. Department of the Interior (DOI) to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. Four PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege that the Colorado BART rule is inadequate to satisfy the Clean Air Act (CAA) mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when the DOI will rule on the petition.

NSP-Minnesota

NSP-Minnesota submitted its BART alternatives analysis for Sherco Units 1 and 2 in October 2006. The MPCA reviewed the BART analyses for all units in Minnesota and determined that overall, compliance with CAIR is better than BART. The MPCA completed their BART determination and proposed SO2 and NOx limits in the draft SIP that are equivalent to the reductions made under CAIR.

In October 2009, the DOI certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2. The EPA is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to visibility impairment and, if so, whether the level of controls proposed by MPCA is appropriate.

The MPCA determined that this certification does not alter the proposed SIP. The SIP proposes BART controls for the Sherco generating facilities that are designed to improve visibility in the national parks, but does not require Selective Catalytic Reduction (SCR) on Units 1 and 2. The MPCA concluded that the minor visibility benefits derived from SCR do not outweigh the substantial costs. In December 2009, the MPCA Citizens Board approved the SIP, which has been submitted to the EPA for approval. The EPA is expected to complete its review of the SIP, as well as the Sherco Units 1 and 2 BART determination before the end of 2010.

Federal Clean Water Act — The federal Clean Water Act (CWA) requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available (BTA) for minimizing adverse environmental impacts. In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants. Several lawsuits were filed against the EPA challenging the phase II rulemaking. In April 2009, the U.S. Supreme Court issued a decision in Entergy Corp. v. Riverkeeper, Inc., concluding that the EPA can consider a cost benefit analysis when establishing BTA. The decision overturned only one aspect of the Court of Appeals’ earlier opinion, and gives the EPA the discretion to consider costs and benefits when it reconsiders its phase II rules. Until the EPA fully responds, the rule’s compliance requirements and associated deadlines will remain unknown. As such, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

As part of NSP-Minnesota’s 2009 CWA permit renewal for the Black Dog plant, the MPCA required that the plant submit a plan for compliance with the CWA. The compliance plan was submitted for MPCA review and approval in April 2010. The MPCA is currently reviewing the proposal in consultation with the EPA. Xcel Energy anticipates approval of the plan by the end of 2010.

Proposed Coal Ash Regulation — In June 2010, the EPA published a proposed rule seeking comment on whether to regulate coal combustion byproducts (often referred to as coal ash) as a special waste (subject to many of the requirements for hazardous waste) or as a solid (nonhazardous) waste. Coal ash is currently exempt from hazardous waste regulation. The EPA's proposal would result in more comprehensive and expensive requirements related to management and disposal of coal ash. The EPA has extended the public comment period on the proposed rule until Nov. 19, 2010. The EPA is also seeking comment on what regulations are appropriate for the beneficial reuse of coal ash. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

PSCo Notice of Violation (NOV) — In July 2002, PSCo received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Comanche Station and Pawnee Station in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid to late 1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the CAA and NSR process. PSCo also 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 disagrees with the assertions contained in the NOV and intends to vigorously defend its position.

Cunningham Draft Compliance Order — On Feb. 18, 2010, SPS received a draft compliance order from the New Mexico Environment Department (NMED) for Cunningham Station. In the draft order, NMED alleges that Cunningham exceeded its permit limits for NOx on 7,336 occasions and failed to report these exceedances as required by its permit. The draft order included a proposed penalty of $16.1 million. On Sept. 28, 2010, the NMED issued a final compliance order, which reduced the alleged NOx exceedances to approximately 4,000 occasions and the proposed penalty to $7.6 million. SPS intends to request an administrative hearing to contest the order.

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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.

Gas Trading Litigation

e prime, inc. (e prime) is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing. e prime has not engaged in natural gas trading or marketing activities since 2003. Thirteen lawsuits have been commenced against e prime and Xcel Energy (and NSP-Wisconsin, in one instance); alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Xcel Energy, e prime, and NSP-Wisconsin deny these allegations, believe they are without merit and will vigorously defend against these lawsuits, including seeking dismissal and summary judgment.

The initial gas-trading lawsuit, a purported class action brought by wholesale natural gas purchasers, was filed in November 2003 in the U.S. District Court in the Eastern District of California. e prime is one of several defendants named in the complaint. This case is captioned Texas-Ohio Energy vs. CenterPoint Energy et al. The other twelve cases arising out of the same or similar set of facts are captioned Fairhaven Power Company vs. EnCana Corporation et al.; Ableman Art Glass vs. EnCana Corporation et al.; Utility Savings and Refund Services LLP vs. Reliant Energy Services Inc. et al.; Sinclair Oil Corporation vs. e prime and Xcel Energy Inc.; Ever-Bloom Inc. vs. Xcel Energy Inc. and e prime et al.; Learjet, Inc. vs. e prime and Xcel Energy Inc et al.; J.P. Morgan Trust Company vs. e prime and Xcel Energy Inc. et al.; Breckenridge Brewery vs. e prime and Xcel Energy Inc. et al.; Missouri Public Service Commission vs. e prime, inc. and Xcel Energy Inc. et al.; Arandell vs. e prime, Xcel Energy, NSP-Wisconsin et al.; NewPage Wisconsin System Inc vs. e prime, Xcel Energy, NSP-Wisconsin et al. and Heartland Regional Medical Center vs. e prime, Xcel Energy et al. Many of these cases involve multiple defendants and have been transferred to Judge Phillip Pro of the U.S. District Court in Nevada, who is the judge assigned to the Western Area Wholesale Natural Gas Antitrust Litigation.

e prime and some other defendants were dismissed from the Breckenridge Brewery lawsuit in February 2008, but Xcel Energy remains a defendant in that lawsuit and e prime Energy Marketing was added as a defendant in February 2008.

No trial dates have been set for any of these lawsuits. In 2009, the parties reached a settlement agreement in the Abelman Art Glass, Ever Bloom, Fairhaven Power Company, Texas-Ohio Energy, and Utility Savings and Refund Services cases. The terms of the settlement did not have a material financial effect upon Xcel Energy. Discovery in most of the remaining cases was completed by Dec. 5, 2009. Trial for all cases venued in Nevada will likely be set for 2011 if pending motions to dismiss are not granted.

In November 2007, the Missouri Public Service Commission case was remanded to Missouri state court. On Jan. 13, 2009, the Missouri state court granted defendants’ motion to dismiss plaintiff’s complaint for lack of standing. Plaintiffs filed an appeal and on Dec. 8, 2009, the Missouri Court of Appeals affirmed the dismissal. The Missouri Supreme Court subsequently granted plaintiff’s motion for transfer but subsequently returned the matter to the Missouri Court of Appeals which simply reaffirmed its earlier dismissal of the complaint.

In March 2009, Newpage Wisconsin System Inc. commenced a lawsuit in state court in Wood County, Wis. The allegations are substantially similar to Arandell and name several of the same defendants, including Xcel Energy, e prime and NSP-Wisconsin. In September 2009, Plaintiffs moved to consolidate the Newpage and Arandell matters. In June 2010, the court denied defendants’ motions to dismiss the Newpage lawsuit on statute of limitations grounds and granted the motion to consolidate New Page and Arandell.

Environmental Litigation

State of Connecticut vs. Xcel Energy Inc. et al. — In 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court in the Southern District of New York against five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO2) emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisance. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. On Sept. 19, 2005, the court granted a motion to dismiss on constitutional grounds. On appeal in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the lower court decision. In August 2010, defendants filed a petition for review with the U.S. Supreme Court.

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Comer vs. Xcel Energy Inc. et al. — In 2006, Xcel Energy received notice of a purported class action lawsuit filed in U.S. District Court in the Southern District of Mississippi. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.” Plaintiffs allege negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane. Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims. In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds. Plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Fifth Circuit. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court decision, in part, concluding that the plaintiffs pleaded sufficient facts to overcome the constitutional challenges that formed the basis for dismissal by the district court. A subsequent petition by defendants, including Xcel Energy, for en banc review was granted. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit ruled that it lacked an en banc quorum of nine active members to hear the case. It dismissed the appeal, which resulted in the reinstatement of the district court’s opinion dismissing the case. Plaintiffs subsequently filed with the U.S. Supreme Court a writ of mandamus, which is a procedure requesting the court to order the Fifth Circuit to review plaintiffs’ earlier appeal. Defendants intend to oppose this request.

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy and 23 other utilities, oil, gas and coal companies. Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village. Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on June 30, 2008. In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds. In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit. All briefs related to this appeal have been filed. It is unknown when the Ninth Circuit will render a final opinion.

Comanche Unit 3 CAA Lawsuit — In July 2009, WildEarth Guardians (WEG) filed a lawsuit in the U.S. District Court in Colorado against PSCo alleging that PSCo violated the CAA by constructing Comanche Unit 3 without a final MACT determination from the Colorado Department of Public Health and Environment, Air Pollution Control Division (APCD). PSCo disputes these claims and filed a motion to dismiss the suit. Comanche Unit 3 was constructed with state-of-the-art emission controls and pursuant to a valid air permit issued by the APCD. In January 2010, WEG sought to enjoin PSCo from constructing, modifying, or operating Comanche Unit 3 prior to receiving a final MACT determination. The court denied WEG’s request for a temporary restraining order on Jan. 26, 2010. In March 2010, the court partially granted and partially denied PSCo’s motion to dismiss. The court requested additional briefing on certain issues related to the MACT determination. Briefing has now been completed, and the court is expected to issue a final ruling in due course.

United States vs. Xcel Energy Inc. et al. — In June 2010, the U.S. Department of Justice and the EPA filed a complaint in the U.S. District Court in Minnesota against Xcel Energy, alleging that Xcel Energy has failed to fully respond to certain information requests issued by the EPA. Over the last ten years, Xcel Energy has responded to numerous information requests from the EPA pursuant to section 114 of the CAA. The requests focused on past projects undertaken at Xcel Energy’s Sherco and Black Dog plants to determine whether these projects were carried out in compliance with the NSR requirements. Xcel Energy has complied with these requests and produced thousands of pages of documents. In June 2009, the EPA issued a supplemental information request which, among other things, asked for ten years of prospective capital project documentation related to projects that may be undertaken in the future at the plants. Xcel Energy believed that the request for future project information exceeded the EPA’s CAA authority and filed a motion to dismiss the lawsuit. The EPA filed a motion for preliminary injunction in which it narrowed its request to two years of prospective capital project documentation. On Sept. 27, 2010, the court denied Xcel Energy’s motion to dismiss and ruled that two years of future documentation is reasonable, but rejected the request for ten years of documentation. The court granted the EPA’s motion for a preliminary injunction and ruled that a limited set of responsive documents be produced. Xcel Energy is complying with this order.

Employment, Tort and Commercial Litigation

Siewert vs. Xcel Energy — In 2004, plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action in Minnesota state court against NSP-Minnesota alleging negligence in the handling, supplying, distributing and selling of electrical power systems; negligence in the construction and maintenance of distribution systems; and failure to warn or adequately test such systems. Plaintiffs allege decreased milk production, injury, and damage to a dairy herd as a result of stray voltage resulting from NSP-Minnesota’s distribution system. Plaintiffs claim losses of approximately $7 million. NSP-Minnesota denies all allegations. In December 2008, the Court of Appeals issued a decision ordering dismissal of plaintiffs’ claims for injunctive relief, but otherwise rejecting NSP-Minnesota’s contentions and ordering the matter remanded for trial. The Minnesota Supreme Court subsequently granted NSP-Minnesota’s petition for further review and heard oral arguments in December 2009. It is uncertain when the Minnesota Supreme Court will render a decision.

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Qwest vs. Xcel Energy Inc. — In 2004, an employee of PSCo was seriously injured when a pole owned by Qwest malfunctioned. In September 2005, the employee commenced an action against Qwest in Colorado state court in Denver. In April 2006, Qwest filed a third party complaint against PSCo based on terms in a joint pole use agreement between Qwest and PSCo. In May 2007, the matter was tried and the jury found Qwest solely liable for the accident and this determination resulted in an award of damages in the amount of approximately $90 million. In April 2009, the Colorado Court of Appeals affirmed the jury verdict insofar as it relates to claims asserted by Qwest against PSCo. Qwest filed a petition for rehearing with the Colorado Supreme Court in June 2009. In February 2010, the Colorado Supreme Court agreed to review the Court of Appeals’ decision as to the punitive damages issue but will not review the Court of Appeals’ decision as it relates to PSCo. Oral arguments are set for December 2010. It is unknown when the Colorado Supreme Court will render a decision.

MGP Insurance Coverage Litigation — In October 2003, NSP-Wisconsin initiated discussions with its insurers regarding the availability of insurance coverage for costs associated with the remediation of four former MGP sites located in Ashland, Chippewa Falls, Eau Claire and La Crosse, Wis. In lieu of participating in discussions, in October 2003, two of NSP-Wisconsin’s insurers, St. Paul Fire & Marine Insurance Co. and St. Paul Mercury Insurance Co., commenced litigation against NSP-Wisconsin in Minnesota state district court. In November 2003, NSP-Wisconsin commenced suit in Wisconsin state court against St. Paul Fire & Marine Insurance Co. and its other insurers. Subsequently, the Minnesota court enjoined NSP-Wisconsin from pursuing the Wisconsin litigation. In July of 2007, the Minnesota trial court granted defendant’s motion for summary judgment, which was affirmed on appeal in August 2009. Pursuant to defendants’ motion, the Wisconsin action was dismissed in March 2010. In April 2010, NSP-Wisconsin appealed this decision to the Wisconsin Court of Appeals. It is unknown when the Wisconsin Court of Appeals will render a decision.

NSP-Wisconsin has reached settlements with 22 insurers, and these insurers have been dismissed from both the Minnesota and Wisconsin actions. NSP-Wisconsin has also reached settlements in principle with Ranger Insurance Company, TIG Insurance Company, Royal Indemnity Company and Globe Indemnity Company.

The PSCW has established a deferral process whereby clean-up costs associated with the remediation of former MGP sites are deferred and, if approved by the PSCW, recovered from ratepayers. Carrying charges associated with these clean-up costs are not subject to the deferral process and are not recoverable from ratepayers. Any insurance proceeds received by NSP-Wisconsin will be credited to ratepayers. None of the aforementioned lawsuit settlements are expected to have a material effect on Xcel Energy’s consolidated financial statements.

Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the U.S. Department of Energy’s (DOE) failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the DOE and NSP-Minnesota. At trial, NSP-Minnesota claimed damages in excess of $100 million through Dec. 31, 2004. In September 2007, the court awarded NSP-Minnesota $116.5 million in damages. In December 2007, the court denied the DOE’s motion for reconsideration. In February 2008, the DOE filed an appeal to the U.S. Court of Appeals for the Federal Circuit, and NSP-Minnesota cross-appealed on the cost of capital issue. It is uncertain when the Court will issue a decision. Results of the judgment will not be recorded in earnings until the appeal, regulatory treatment and amounts to be shared with ratepayers have been resolved. Given the uncertainties, it is unclear as to how much, if any, of this judgment will ultimately have a net impact on earnings.

In August 2007, NSP-Minnesota filed a second complaint against the DOE in the U.S. Court of Federal Claims (NSP II), again claiming breach of contract damages for the DOE’s continuing failure to abide by the terms of the contract. This lawsuit will claim damages for the period Jan. 1, 2005 through Dec. 31, 2008, which includes costs associated with the storage of spent nuclear fuel at Prairie Island and Monticello, as well as the costs of complying with state regulation relating to the storage of spent nuclear fuel. Per the court’s scheduling order, NSP-Minnesota believes that it has suffered damages in excess of $250 million. The DOE claims NSP-Minnesota is entitled to at most approximately $55 million. Trial is expected to take place in early 2011.

Mallon vs. Xcel Energy Inc. — In August 2007, Xcel Energy, PSCo and PSRI (Plaintiffs) commenced a lawsuit in Colorado state court against Theodore Mallon (Mallon) and TransFinancial Corporation seeking damages for, among other things, breach of contract and breach of fiduciary duties associated with the sale of COLI policies. In May 2008, Plaintiffs filed an amended complaint that, among other things, adds Provident as a defendant and asserts claims for breach of contract, unjust enrichment and fraudulent concealment against the insurance company. In November 2009, Plaintiffs reached a settlement with Mallon and TransFinancial Corporation, where Mallon agreed to pay Plaintiffs a specified amount of money and the parties agreed to mutually release each other from all claims.

In July 2010, Plaintiffs entered into a settlement agreement with Provident and Reassure America Life Insurance Company. Under the terms of the settlement, Provident paid Plaintiffs $25 million. Xcel Energy recorded this settlement of $25 million in the third quarter of 2010. The $25 million proceeds are not subject to income taxes.

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Cabin Creek Hydro Generating Station Accident — In October 2007, employees of RPI Coatings Inc. (RPI), a contractor retained by PSCo, were applying an epoxy coating to the inside of a penstock at PSCo’s Cabin Creek Hydro Generating Station (CCH) near Georgetown, Colo. A fire occurred inside a pipe used to deliver water from a reservoir to the hydro facility. Five RPI employees were unable to exit the pipe and rescue crews confirmed their deaths. The accident was investigated by several state and federal agencies, including the federal Occupational Safety and Health Administration (OSHA) and the U.S. Chemical Safety Board (CSB) and the Colorado Bureau of Investigations.

In March 2008, OSHA proposed penalties totaling $189,900 for 22 serious violations and three willful violations arising out of the accident. In April 2008, Xcel Energy notified OSHA of its decision to contest all of the proposed citations. On May 28, 2008, the Secretary of Labor filed its complaint, and Xcel Energy subsequently filed its answer on June 17, 2008. The Court ordered this proceeding stayed until March 3, 2009 and has subsequently extended the stay until the criminal proceedings have concluded.

A lawsuit was filed in Colorado state court in Denver on behalf of four of the deceased workers and four of the injured workers (Foster, et. al. v. PSCo, et. al.). PSCo and Xcel Energy were named as defendants in that case, along with RPI Coatings and related companies and the two other contractors who also performed work in connection with the relining project at Cabin Creek. A second lawsuit (Ledbetter et. al vs. PSCo et. al) was also filed in Colorado state court in Denver on behalf of three employees allegedly injured in the accident. A third lawsuit was filed on behalf of one of the deceased RPI workers in the California state court (Aguirre v. RPI, et. al.), naming PSCo, RPI, and the two other contractors as defendants. The court subsequently dismissed the Aguirre lawsuit. Settlements were subsequently reached in all three lawsuits. These confidential settlements did not have a material effect on the financial statements of Xcel Energy or its subsidiaries.

On Aug. 28, 2009, the U.S. Government announced that Xcel Energy and PSCo have been charged with five misdemeanor counts in federal court in Colorado for violation of an OSHA regulation related to the accident at Cabin Creek in October 2007. RPI Coatings, the contractor performing the work at the plant, and two individuals employed by RPI have also been indicted. On Sept. 22, 2009, both Xcel Energy and PSCo entered a not guilty plea, and both will vigorously defend against these charges. In December 2009, Xcel Energy and PSCo filed two separate motions to dismiss. On March 29, 2010, the court issued an order denying both motions. No trial date has yet been set.

In August 2010, the CSB issued a report related to its investigation of the CCH accident. The report contains several findings and recommendations, some of which pertain to PSCo. Consistent with its delegated authority, the CSB investigation did not result in the issuance of any fines or penalties. PSCo intends to respond to the CSB concerning its recommendations in due course.

Stone & Webster, Inc. vs. PSCo — In July 2009, Stone & Webster, Inc. (Shaw) filed a complaint against PSCo in State District Court in Denver, Colo. for damages allegedly arising out of its construction work on the Comanche Unit 3 coal-fired plant. Shaw, a contractor retained to perform certain engineering, procurement and construction work on Comanche Unit 3, alleges, among other things, that PSCo mismanaged the construction of Comanche Unit 3. Shaw further claims that this alleged mismanagement caused delays and damages. The complaint also alleges that Xcel Energy and related entities guaranteed Shaw $10 million in future profits under the terms of a 2003 settlement agreement. Shaw alleges that it will not receive the $10 million to which it is entitled. Accordingly, Shaw seeks an amount up to $10 million relating to the 2003 settlement agreement. In total, Shaw seeks approximately $144 million in damages.

PSCo denies these allegations and believes the claims are without merit. PSCo filed an answer and counterclaim in August 2009, denying the allegations in the complaint and alleging that Shaw has failed to discharge its contractual obligations and has caused delays, and that PSCo is entitled to liquidated damages and excess costs incurred. In total, PSCo is seeking approximately $82 million in damages. In June 2010, PSCo exercised its contractual right to draw on Shaw’s letter of credit in the total amount of approximately $29.6 million. In September 2010, Shaw filed a second lawsuit related to PSCo’s decision to draw on the letter of credit. PSCo denies the merits of this claim.

Trial commenced on Oct. 18, 2010 and is expected to last approximately four weeks. The trial will address only those issues raised in the first complaint and will not include Shaw’s claim asserted in the second lawsuit related to the letter of credit.

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Fru-Con Construction Corporation (Fru-Con) vs. Utility Engineering Corporation (UE) et al. — In March 2005, Fru-Con commenced a lawsuit in U.S. District Court in 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. In August 2005, the court granted UE’s motion to dismiss. Because SMUD remains a defendant in this action, the court has not entered a final judgment subject to an appeal with respect to its order to dismiss UE from the lawsuit. Because this lawsuit was commenced prior to the April 2005, closing of the sale of UE to Zachry, Xcel Energy is obligated to indemnify Zachry for damages related to this case up to $17.5 million. Pursuant to the terms of its professional liability policy, UE is insured up to $35 million.

Connie DeWeese vs. PSCo — In November 2008, there was an explosion in Pueblo, Colo., which destroyed a tavern and a neighboring store. The explosion killed one person and injured seven people. The Pueblo Fire Department and the Federal Bureau of Alcohol, Tobacco and Firearms have determined a natural gas leak from a pipeline under the street led to the explosion. In February 2010, a wrongful death/personal injury lawsuit was filed in Colorado District Court in Pueblo, Colorado against PSCo and the City of Pueblo by several parties that were allegedly injured, as a result of this explosion. The plaintiffs are also alleging economic and noneconomic damages. The lawsuit alleges that the accident occurred as a result of PSCo’s negligence. A related lawsuit was filed in March 2010 by Seneca Insurance Company, which insured Branch Inn, LLC and Branch Inn Enterprises, LLC. The Plaintiffs are alleging destruction of the building and disruption of the business. Both lawsuits allege that the accident occurred as a result of PSCo’s negligence. PSCo denies liability for this accident. The cases have been consolidated. In June 2010, the court granted, in part, PSCo’s motion to dismiss certain of plaintiffs’ claims related to, among other things, strict liability. In July 2010, a third related lawsuit was filed by Truck Insurance Exchange against PSCo and the City of Pueblo to recover damages allegedly paid by the plaintiff insurance company to its insured as a result of the explosion. In September 2010, six plaintiffs filed a fourth lawsuit, Vigil vs. Xcel Energy, in Hennepin County District Court in Minneapolis, Minn., alleging personal injury and property damage as a result of the November 2008 explosion. In response, a motion has been filed to dismiss the lawsuit for improper venue and for naming the wrong party defendant.

8.	Short-Term Borrowings and Other Financing Instruments

Commercial Paper — The following table presents commercial paper outstanding for Xcel Energy:

(Millions of Dollars)	Sept. 30, 2010			Dec. 31, 2009
Commercial paper outstanding	$	40		$	459
Weighted average interest rate		0.33	%		0.36	%
Commercial paper borrowing limit	$	2,177		$	2,177

Credit Facility Bank Borrowings — Xcel Energy and its subsidiaries had no credit facility bank borrowings at Sept. 30, 2010 and Dec. 31, 2009.

Money Pool — Xcel Energy and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings from the utilities between each other. The holding company may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in the holding company. The money pool investments and borrowings are eliminated upon consolidation.

9.	Long-Term Borrowings and Other Financing Instruments

In February 2010, SPS redeemed its $25.0 million pollution control obligations, securing pollution control revenue bonds, due July 1, 2016.

In May 2010, Xcel Energy issued $550 million of 4.70 percent unsecured senior notes, due May 15, 2020. Xcel Energy added the net proceeds from the sale of the notes to its general funds and used the proceeds to repay commercial paper and fund equity investments in its utility subsidiaries.

In August 2010, NSP-Minnesota issued $250 million of 1.95 percent first mortgage bonds, due Aug. 15, 2015 and $250 million of 4.85 percent first mortgage bonds, due Aug. 15, 2040. NSP-Minnesota added the net proceeds from the sale of the bonds to its general funds and applied a portion of the proceeds to the repayment of short-term debt, including short-term debt incurred to fund the repayment at maturity of $175 million of 4.75 percent first mortgage bonds due Aug. 1, 2010. The balance of the net proceeds was used for general corporate purposes, including the funding of capital expenditures.

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10.	Derivative Instruments and Fair Value Measurements

Xcel Energy and its utility subsidiaries enter into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices, as well as variances in forecasted weather.

Short-Term Wholesale and Commodity Trading Risk — Xcel Energy’s utility subsidiaries conduct various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. Xcel Energy’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

Interest Rate Derivatives — Xcel Energy and its utility 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 generally designated as cash flow hedges for accounting purposes.

At Sept. 30, 2010, accumulated other comprehensive income (OCI) related to interest rate derivatives included $0.7 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

Commodity Derivatives — Xcel Energy’s utility subsidiaries enter into derivative instruments to manage variability of future cash flows from changes in commodity prices in their electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, gas for resale and vehicle fuel.

At Sept. 30, 2010, Xcel Energy had various vehicle fuel related contracts designated as cash flow hedges extending through December 2012. Xcel Energy’s utility subsidiaries also enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and nine months ended Sept. 30, 2010.

At Sept. 30, 2010, accumulated OCI related to commodity derivative cash flow hedges included $0.7 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, Xcel Energy’s utility subsidiaries enter into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving their electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in income, subject to applicable customer margin-sharing mechanisms.

The following table details the gross notional amounts of commodity forwards, options, and financial transmission rights (FTRs) at Sept. 30, 2010 and Dec. 31, 2009:

(Amounts in Thousands) (a)(b)	Sept. 30, 2010		Dec. 31, 2009
Megawatt hours (MWh) of electricity		58,879		37,932
MMBtu of natural gas		95,443		57,181
Gallons of vehicle fuel		1,195		3,580

(a) Amounts are not reflective of net positions in the underlying commodities.

(b) Notional amounts for options are also included on a gross basis, but are weighted for the probability of exercise.

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Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on Xcel Energy’s accumulated OCI, included in the consolidated statements of common stockholders’ equity and comprehensive income, is detailed in the following tables:

	Three Months Ended Sept. 30,
(Thousands of Dollars)	2010			2009
Accumulated other comprehensive loss related to cash flow hedges at July 1	$	(9,590	)	$	(9,782	)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		35			(6,589	)
After-tax net realized losses on derivative transactions reclassified into earnings		749			1,032
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(8,806	)	$	(15,339	)

	Nine Months Ended Sept. 30,
(Thousands of Dollars)	2010			2009
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(6,435	)	$	(13,113	)
After-tax net unrealized losses related to derivatives accounted for as hedges		(4,350	)		(5,770	)
After-tax net realized losses on derivative transactions reclassified into earnings		1,979			3,544
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(8,806	)	$	(15,339	)

Xcel Energy had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2010 and Sept. 30, 2009. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2010 and Sept. 30, 2009, respectively, on OCI, regulatory assets and liabilities, and income:

	Three Months Ended Sept. 30, 2010
	Fair Value Changes Recognized During the Period in:					Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains Recognized During the Period in Income
(Thousands of Dollars)	Other Comprehensive Income (Losses)		Regulatory Assets and Liabilities			Other Comprehensive Income			Regulatory Assets and Liabilities			Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	-		$	344	(a)	$	-		$	-
Vehicle fuel and other commodity		61		-			933	(e)		-			-
Total	$	61	$	-		$	1,277		$	-		$	-

Other derivative instruments:
Trading commodity	$	-	$	-		$	-		$	-		$	4,320	(b)
Electric commodity		-		6,568			-			(8,259	)(c)		-
Natural gas commodity		-		(65,303	)		-			925	(d)		-
Total	$	-	$	(58,735	)	$	-		$	(7,334	)	$	4,320

	Nine Months Ended Sept. 30, 2010
	Fair Value Changes Recognized During the Period in:						Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains Recognized During the Period in Income
(Thousands of Dollars)	Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities			Other Comprehensive Income			Regulatory Assets and Liabilities			Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges:
Interest rate	$	(7,210	)	$	-		$	763	(a)	$	-		$	-
Vehicle fuel and other commodity		(261	)		-			2,626	(e)		-			-
Total	$	(7,471	)	$	-		$	3,389		$	-		$	-

Other derivative instruments:
Trading commodity	$	-		$	-		$	-		$	-		$	9,925	(b)
Electric commodity		-			(3,014	)		-			(13,097	)(c)		-
Natural gas commodity		-			(106,009	)		-			5,632	(d)		-
Other		-			-			-			-			135	(b)
Total	$	-		$	(109,023	)	$	-		$	(7,465	)	$	10,060

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	Three Months Ended Sept. 30, 2009
	Fair Value Changes Recognized During the Period in:					Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities		Other Comprehensive Income			Regulatory Assets and Liabilities

Derivatives designated as cash flow hedges:
Interest rate	$	(10,846	)	$	-	$	291	(a)	$	-		$	-
Natural gas commodity		-			1,457		-			202	(d)		-
Vehicle fuel and other commodity		(304	)		-		1,426	(e)		-