Edgar Filing: XCEL ENERGY INC

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2011

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. xYes 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). xYes 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 x		Accelerated filer o
Non-accelerated filer o (Do not check if smaller reporting company)		Smaller reporting company o

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

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. 20, 2011
Common Stock, $2.50 par value		484,955,743 shares

Table of Contents

TABLE OF CONTENTS

PART I		FINANCIAL INFORMATION	3
	Item 1 —	Financial Statements (unaudited)	3
		CONSOLIDATED STATEMENTS OF INCOME	3
		CONSOLIDATED STATEMENTS OF CASH FLOWS	4
		CONSOLIDATED BALANCE SHEETS	5
		CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME	6
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	8
	Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
	Item 3 —	Quantitative and Qualitative Disclosures about Market Risk	61
	Item 4 —	Controls and Procedures	62
PART II		OTHER INFORMATION	62
	Item 1 —	Legal Proceedings	62
	Item 1A —	Risk Factors	62
	Item 5 —	Other Information	64
	Item 6 —	Exhibits	64
SIGNATURES			65
		Certifications Pursuant to Section 302	1
		Certifications Pursuant to Section 906	1
		Statement Pursuant to Private Litigation	1

This Form 10-Q is filed by Xcel Energy Inc., also referred to herein as Xcel Energy Holding Co. 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). Xcel Energy Inc. and its consolidated subsidiaries is also referred to herein as Xcel Energy. 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,
	2011			2010			2011			2010
Operating revenues
Electric	$	2,619,424		$	2,440,917		$	6,777,793		$	6,477,211
Natural gas		194,930			170,594			1,251,817			1,210,154
Other		17,244			17,276			56,750			56,648
Total operating revenues		2,831,598			2,628,787			8,086,360			7,744,013

Operating expenses
Electric fuel and purchased power		1,150,252			1,110,781			3,071,493			3,085,347
Cost of natural gas sold and transported		87,107			66,571			793,539			774,647
Cost of sales — other		7,154			8,848			22,100			21,244
Other operating and maintenance expenses		532,962			509,634			1,575,159			1,507,247
Conservation and demand side management program expenses		71,280			60,861			212,075			174,451
Depreciation and amortization		242,329			221,671			696,316			639,303
Taxes (other than income taxes)		89,018			81,791			278,077			244,175
Total operating expenses		2,180,102			2,060,157			6,648,759			6,446,414

Operating income		651,496			568,630			1,437,601			1,297,599

Other income, net		2,550			27,450			8,295			30,134
Equity earnings of unconsolidated subsidiaries		7,423			7,670			22,813			22,433
Allowance for funds used during construction — equity		11,840			13,464			38,690			39,750

Interest charges and financing costs

Interest charges — includes other financing costs of $6,279, $5,229, $17,724 and $15,386, respectively		148,011			144,849			438,703			430,134
Allowance for funds used during construction — debt		(6,301	)		(6,323	)		(21,575	)		(20,635	)
Total interest charges and financing costs		141,710			138,526			417,128			409,499

Income from continuing operations before income taxes		531,599			478,688			1,090,271			980,417
Income taxes		193,304			166,200			389,838			364,964
Income from continuing operations		338,295			312,488			700,433			615,453
Income (loss) from discontinued operations, net of tax		37			(182	)		230			3,747
Net income		338,332			312,306			700,663			619,200
Dividend requirements on preferred stock		1,414			1,060			3,534			3,180
Premium on redemption of preferred stock		3,260			-			3,260			-
Earnings available to common shareholders	$	333,658		$	311,246		$	693,869		$	616,020

Weighted average common shares outstanding:
Basic		485,344			460,471			484,640			459,816
Diluted		485,894			462,019			485,152			460,722

Earnings per average common share — basic:
Income from continuing operations	$	0.69		$	0.68		$	1.43		$	1.33
Income from discontinued operations		-			-			-			0.01
Earnings per share	$	0.69		$	0.68		$	1.43		$	1.34

Earnings per average common share — diluted:
Income from continuing operations	$	0.69		$	0.67		$	1.43		$	1.33
Income from discontinued operations		-			-			-			0.01
Earnings per share	$	0.69		$	0.67		$	1.43		$	1.34

Cash dividends declared per common share	$	0.26		$	0.25		$	0.77		$	0.75

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,
	2011			2010

Operating activities
Net income	$	700,663		$	619,200
Remove income from discontinued operations		(230	)		(3,747	)
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		709,936			648,089
Conservation and demand side management program amortization		7,979			18,694
Nuclear fuel amortization		75,292			78,150
Deferred income taxes		389,355			325,530
Amortization of investment tax credits		(4,740	)		(4,782	)
Allowance for equity funds used during construction		(38,690	)		(39,750	)
Equity earnings of unconsolidated subsidiaries		(22,813	)		(22,433	)
Dividends from unconsolidated subsidiaries		25,481			23,821
Share-based compensation expense		31,943			27,272
Net realized and unrealized hedging and derivative transactions		14,537			(61,136	)
Changes in operating assets and liabilities:
Accounts receivable		(33,649	)		31,876
Accrued unbilled revenues		155,854			159,769
Inventories		(47,207	)		(25,520	)
Other current assets		60,216			32,201
Accounts payable		(82,681	)		(283,123	)
Net regulatory assets and liabilities		134,338			85,128
Other current liabilities		5,969			(45,984	)
Pension and other employee benefit obligations		(136,538	)		(9,481	)
Change in other noncurrent assets		21,211			(231	)
Change in other noncurrent liabilities		(42,108	)		(27,220	)
Net cash provided by operating activities		1,924,118			1,526,323

Investing activities
Utility capital/construction expenditures		(1,604,206	)		(1,561,987	)
Allowance for equity funds used during construction		38,690			39,750
Merricourt refund		101,261			-
Merricourt deposit		(90,833	)		-
Purchase of investments in external decommissioning fund		(1,741,907	)		(3,309,093	)
Proceeds from the sale of investments in external decommissioning fund		1,741,909			3,314,356
Investment in WYCO Development LLC		(1,768	)		(6,119	)
Change in restricted cash		(99,972	)		91
Other investments		(4,129	)		2,044
Net cash used in investing activities		(1,660,955	)		(1,520,958	)

Financing activities
Repayment of short-term borrowings, net		(416,400	)		(419,000	)
Proceeds from issuance of long-term debt		688,686			1,038,368
Repayment of long-term debt, including reacquisition premiums		(104,525	)		(200,452	)
Proceeds from issuance of common stock		6,164			5,869
Dividends paid		(351,370	)		(322,187	)
Net cash (used in) provided by financing activities		(177,445	)		102,598

Net increase in cash and cash equivalents		85,718			107,963
Cash and cash equivalents at beginning of period		108,437			115,648
Cash and cash equivalents at end of period	$	194,155		$	223,611

Supplemental disclosure of cash flow information:
Cash paid for interest, net of amounts capitalized	$	(405,111	)	$	(389,719	)
Cash received (paid) for income taxes, net		53,567			(17,410	)
Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable	$	136,236		$	62,663
Issuance of common stock for reinvested dividends and 401(k) plans		55,319			48,685

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, 2011			Dec. 31, 2010
Assets
Current assets
Cash and cash equivalents	$	194,155		$	108,437
Restricted cash		100,007			-
Accounts receivable, net		752,123			718,474
Accrued unbilled revenues		552,837			708,691
Inventories		608,007			560,800
Regulatory assets		412,211			388,541
Derivative instruments		50,281			54,079
Prepayments and other		191,852			193,621
Total current assets		2,861,473			2,732,643

Property, plant and equipment, net		21,729,488			20,663,082

Other assets
Nuclear decommissioning fund and other investments		1,399,527			1,476,435
Regulatory assets		2,224,509			2,151,460
Derivative instruments		158,362			184,026
Other		164,495			180,044
Total other assets		3,946,893			3,991,965
Total assets	$	28,537,854		$	27,387,690

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	462,414		$	55,415
Short-term debt		50,000			466,400
Accounts payable		837,259			979,750
Regulatory liabilities		309,032			156,038
Taxes accrued		250,135			254,320
Accrued interest		162,374			163,907
Dividends payable		127,497			122,847
Derivative instruments		125,514			61,745
Other		328,958			276,111
Total current liabilities		2,653,183			2,536,533

Deferred credits and other liabilities
Deferred income taxes		3,809,638			3,390,027
Deferred investment tax credits		88,197			92,937
Regulatory liabilities		1,133,747			1,179,765
Asset retirement obligations		1,293,424			969,310
Derivative instruments		265,481			285,986
Customer advances		256,764			269,087
Pension and employee benefit obligations		829,364			962,767
Other		221,616			249,635
Total deferred credits and other liabilities		7,898,231			7,399,514

Commitments and contingent liabilities
Capitalization
Long-term debt		9,450,157			9,263,144
Preferred stockholders' equity		104,980			104,980
Common stock – $2.50 par value per share		1,212,369			1,205,834
Additional paid in capital		5,280,463			5,229,075
Retained earnings		2,019,440			1,701,703
Accumulated other comprehensive loss		(80,969	)		(53,093	)
Total common stockholders' equity		8,431,303			8,083,519
Total liabilities and equity	$	28,537,854		$	27,387,690

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
	Shares		Par Value		Additional Paid In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stockholders' Equity
Three Months Ended Sept. 30, 2011 and 2010
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, 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

Balance at June 30, 2011		484,543	$	1,211,356	$	5,261,687	$	1,812,505		$	(50,983	)	$	8,234,565
Net income								338,332						338,332
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $515											743			743
Net derivative instrument fair value changes, net of tax of $(20,142)											(30,788	)		(30,788	)
Unrealized gain - marketable securities, net of tax of $41											59			59
Comprehensive income for the period														308,346
Dividends declared:
Cumulative preferred stock								(1,414	)					(1,414	)
Common stock								(126,723	)					(126,723	)
Premium on redemption of preferred stock								(3,260	)					(3,260	)
Issuances of common stock		405		1,013		8,738								9,751
Share-based compensation						10,038								10,038
Balance at Sept. 30, 2011		484,948	$	1,212,369	$	5,280,463	$	2,019,440		$	(80,969	)	$	8,431,303

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
	Shares		Par Value		Additional Paid In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stockholders' Equity
Nine Months Ended Sept. 30, 2011 and 2010
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, net of tax of $(1,711)											(2,371	)		(2,371	)
Unrealized gain - 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

Balance at Dec. 31, 2010		482,334	$	1,205,834	$	5,229,075	$	1,701,703		$	(53,093	)	$	8,083,519
Net income								700,663						700,663
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $1,591											2,290			2,290
Net derivative instrument fair value changes, net of tax of $(19,750)											(30,276	)		(30,276	)
Unrealized loss - marketable securities, net of tax of $76											110			110
Comprehensive income for the period														672,787
Dividends declared:
Cumulative preferred stock								(3,534	)					(3,534	)
Common stock								(376,132	)					(376,132	)
Premium on redemption of preferred stock								(3,260	)					(3,260	)
Issuances of common stock		2,614		6,535		18,462								24,997
Share-based compensation						32,926								32,926
Balance at Sept. 30, 2011		484,948	$	1,212,369	$	5,280,463	$	2,019,440		$	(80,969	)	$	8,431,303

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, 2011 and Dec. 31, 2010; the results of its operations and changes in stockholders’ equity for the three and nine months ended Sept. 30, 2011 and 2010; and its cash flows for the nine months ended Sept. 30, 2011 and 2010. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2011 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, 2010 balance sheet information has been derived from the audited 2010 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2010. 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 on an annual basis 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 Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2010, filed with the SEC on Feb. 28, 2011. 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

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2010, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2.	Accounting Pronouncements

Recently Issued

Fair Value Measurement — In May 2011, the Financial Accounting Standards Board (FASB) issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (Accounting Standards Update (ASU) No. 2011-04), which provides additional guidance for fair value measurements. These updates to the FASB Accounting Standards Codification (ASC or Codification) include clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders’ equity and disclosures regarding the sensitivity of Level 3 measurements to changes in valuation model inputs. These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011. Xcel Energy does not expect the implementation of this guidance to have a material impact on its consolidated financial statements.

Comprehensive Income — In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05), which updates the Codification to require the presentation of the components of net income, the components of other comprehensive income (OCI) and total comprehensive income in either a single continuous statement of comprehensive income or in two separate, but consecutive statements of net income and comprehensive income. These updates do not affect the items reported in OCI or the guidance for reclassifying such items to net income. These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011. Xcel Energy does not expect the implementation of this presentation guidance to have a material impact on its consolidated financial statements.

Multiemployer Plans — In September 2011, the FASB issued Multiemployer Plans (Subtopic 715-80) — Disclosures about an Employer’s Participation in a Multiemployer Plan (ASU No. 2011-09), which updates the Codification to require certain disclosures about an entity’s involvement with multiemployer pension and other postretirement benefit plans. These updates do not affect recognition and measurement guidance for an employer’s participation in multiemployer plans, but rather require additional disclosure such as the nature of multiemployer plans and the employer’s participation, contributions to the plans and details regarding significant plans. These updates to the Codification are effective for annual periods ending after Dec. 15, 2011. Xcel Energy does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.

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3.	Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2011			Dec. 31, 2010
Accounts receivable, net
Accounts receivable	$	806,360		$	773,037
Less allowance for bad debts		(54,237	)		(54,563	)
	$	752,123		$	718,474
Inventories
Materials and supplies	$	205,736		$	196,081
Fuel		205,126			188,566
Natural gas		197,145			176,153
	$	608,007		$	560,800
Property, plant and equipment, net
Electric plant	$	26,437,558		$	24,993,582
Natural gas plant		3,574,976			3,463,343
Common and other property		1,536,759			1,555,287
Plant to be retired (a)		182,487			236,606
Construction work in progress		1,169,746			1,186,433
Total property, plant and equipment		32,901,526			31,435,251
Less accumulated depreciation		(11,484,612	)		(11,068,820	)
Nuclear fuel		1,928,912			1,837,697
Less accumulated amortization		(1,616,338	)		(1,541,046	)
	$	21,729,488		$	20,663,082

(a)

In 2009, in accordance with the Colorado Public Utilities Commission (CPUC)’s approval of PSCo’s 2007 Colorado resource plan and subsequent rate case decisions, PSCo agreed to early retire its Cameo Units 1 and 2, Arapahoe Units 3 and 4 and Zuni Units 1 and 2 facilities. In 2010, in response to the Clean Air Clean Jobs Act (CACJA), the CPUC approved the early retirement of Cherokee Units 1, 2 and 3, Arapahoe Unit 3 and Valmont Unit 5 between 2011 and 2017. Amounts are presented net of accumulated depreciation.

4.	Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2010 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit — Xcel Energy files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return expired in September 2011. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expires in September 2012. The Internal Revenue Service (IRS) commenced an examination of tax years 2008 and 2009 in the third quarter of 2010. As of Sept. 30, 2011, 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, 2011, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows:

State		Year
Colorado		2006
Minnesota		2007
Texas		2007
Wisconsin		2006

As of Sept. 30, 2011, there were 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 effective tax rate (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 benefits is as follows:

(Millions of Dollars)	Sept. 30, 2011		Dec. 31, 2010
Unrecognized tax benefit — Permanent tax positions	$	3.5	$	5.9
Unrecognized tax benefit — Temporary tax positions		31.7		34.6
Unrecognized tax benefit balance	$	35.2	$	40.5

The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(Millions of Dollars)		Sept. 30, 2011				Dec. 31, 2010
NOL and tax credit carryforwards		$	(33.3	)		$	(38.0	)

The decrease in the unrecognized tax benefit balance for the nine months ended Sept. 30, 2011 of $5.3 million was due primarily to the resolution of certain federal audit matters and adjustments for prior year’s activity. Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefits could decrease by up to approximately $24 million.

The payable for interest related to unrecognized tax benefits is substantially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Sept. 30, 2011 and Dec. 31, 2010 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2011 or Dec. 31, 2010.

5.	Rate Matters

Except to the extent noted below, the circumstances set forth in Note 13 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2010 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)

NSP-Minnesota Electric Rate Case — In November 2010, NSP-Minnesota filed a request with the MPUC to increase annual electric rates in Minnesota for 2011 by approximately $150 million, or an increase of 5.62 percent and an additional increase of $48.3 million, or 1.81 percent in 2012. The rate filing was based on a 2011 forecast test year and included a requested return on equity (ROE) of 11.25 percent, an electric rate base of approximately $5.6 billion and an equity ratio of 52.56 percent.

The MPUC approved an interim rate increase of $123 million, subject to refund, effective Jan. 2, 2011. The interim rates will remain in effect until the MPUC makes its final decision on the case.

In June 2011, NSP-Minnesota revised its requested rate increase to $122.8 million, reflecting a revised ROE of 10.85 percent and other adjustments. The Division of Energy Resources (DOER) revised its recommended rate increase to approximately $84.7 million in 2011 and an additional rate increase of $34 million in 2012, reflecting an ROE of 10.37 percent. The primary differences between the NSP-Minnesota requested rate increase and the DOER updated recommendation are associated with ROE and compensation related issues.

In August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and a 2012 step increase of approximately $29 million. The revisions are due to NSP-Minnesota’s decision to delay the Monticello nuclear plant extended power uprate from the fall of 2011 to the fall of 2012. Subsequently, NSP-Minnesota anticipates prolonging the extended power uprate to the spring 2013 refueling outage.

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NSP-Minnesota has recorded a provision for revenue subject to refund of approximately $27 million for the first nine months of 2011, of which $12 million was recorded during the three months ended Sept. 30, 2011. The provision reflects an outcome that is consistent with the DOER position on various issues.

The MPUC decision is expected in the first quarter of 2012.

Pending and Recently Concluded Regulatory Proceedings — North Dakota Public Service Commission (NDPSC)

NSP-Minnesota North Dakota Electric Rate Case — In December 2010, NSP-Minnesota filed a request with the NDPSC to increase 2011 electric rates in North Dakota by approximately $19.8 million, or an increase of 12 percent in 2011 and a step increase of $4.2 million, or 2.6 percent in 2012. The rate filing is based on a 2011 forecast test year and includes a requested ROE of 11.25 percent, an electric rate base of approximately $328 million and an equity ratio of 52.56 percent.

The NDPSC approved an interim rate increase of approximately $17.4 million, subject to refund, effective Feb. 18, 2011. The interim rates will remain in effect until the NDPSC makes its final decision on the case.

In May 2011, NSP-Minnesota revised its rate request to approximately $18.0 million, or an increase of 11 percent, for 2011 and $2.4 million, or 1.4 percent, for the additional increase in 2012, due to the termination of the Merricourt wind project.

In September 2011, NSP-Minnesota reached a settlement with the NDPSC Advocacy Staff. If approved, the settlement would result in a rate increase of $13.7 million in 2011 and an additional step increase of $2.0 million in 2012, based on a 10.4 percent ROE and black box settlement for all other issues. To address 2011 sales coming in below test year projections, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase.

In October 2011, the NDPSC held hearings on the settlement. An NDPSC decision is expected in the fourth quarter of 2011 with final rates expected to be implemented in the first quarter of 2012.

Pending and Recently Concluded Regulatory Proceedings — South Dakota Public Utilities Commission (SDPUC)

NSP-Minnesota South Dakota Electric Rate Case — In June 2011, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $14.6 million annually, effective in 2012. The proposed increase included $0.7 million in revenues currently recovered through automatic recovery mechanisms. The request is based on a 2010 historic test year adjusted for known and measurable changes, a requested ROE of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent. NSP-Minnesota also requested approval of a nuclear cost recovery rider to recover the actual investment cost of the Monticello nuclear plant life cycle management and extended power uprate project that is not reflected in the test year.

As a result of delays in the South Dakota rate case process, NSP-Minnesota anticipates requesting implementation of interim rates beginning Jan. 1, 2012 in the fourth quarter of 2011. A final decision on interim rates is expected in the first quarter of 2012.

Electric, Purchased Gas and Resource Adjustment Clauses

Conservation Improvement Program (CIP) Rider — CIP expenses are recovered through base rates and a rider that is adjusted annually. Under the 2010 electric CIP rider request approved by the MPUC in October 2010, NSP-Minnesota recovered $67.3 million through the rider during November 2010 to September 2011. This is in addition to $48.5 million recovered through base rates. NSP-Minnesota recovered $20.6 million through the natural gas CIP rider approved in November 2010, during December 2010 to September 2011. This is in addition to $3.3 million recovered in base rates.

In 2011, NSP-Minnesota filed its annual rider petitions requesting recovery of $84.8 million of electric CIP expenses and financial incentives and $13.6 million of natural gas CIP expenses and financial incentives to be recovered during October 2011 through September 2012. This proposed recovery through the riders is in addition to an estimated $52.6 million and $3.8 million through electric and gas base rates, respectively.

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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. The primary components of RDF costs are legislatively mandated expenses such as renewable energy production incentive payments and bonus solar rebates. In October 2010, NSP-Minnesota filed its annual request to recover $19.2 million in expenses for 2011. In June 2011, the MPUC approved recovery of the costs requested.

In October 2011, NSP-Minnesota filed its annual request to recover $17.3 million in expenses for 2012.

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 September 2011, the MPUC approved a TCR rider expected to recover $11.5 million in 2011, as well as $22.3 million in 2012. Rates are expected to be effective beginning Nov. 1, 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 September 2011, the MPUC approved a RES rider to recover $40.8 million during 2011. The MPUC also ordered that $9.5 million of over-recovery be credited to customers during November 2011, and to begin collecting forecasted Dec. 1, 2011 through Dec. 31, 2012 revenue requirements of $43.1 million beginning Dec. 1, 2011.

Annual Automatic Adjustment Report — In September 2011, NSP-Minnesota filed its annual electric and natural gas automatic adjustment reports for July 1, 2010 through June 30, 2011. During that time period, $822.8 million in fuel and purchased energy costs were recovered from Minnesota electric customers through the fuel clause adjustment. In addition, approximately $371.6 million of purchased natural gas and transportation costs were recovered from Minnesota natural gas customers through the purchased gas adjustment.

The DOER recommended approval of the 2009/2010 gas automatic adjustment report in June 2011 for recovery of $354.5 million, and the report is pending MPUC action. The 2009/2010 electric automatic adjustment report for recovery of $749.5 million is pending DOER comments and MPUC action.

The MPUC approved the 2008/2009 gas automatic adjustment report in March 2011 for recovery of $500.8 million. Approval of the 2008/2009 electric automatic adjustment report for recovery of $803.6 million is pending DOER comments and MPUC action.

NSP-Wisconsin

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

NSP-Wisconsin 2011 Electric and Gas Rate Case — In June 2011, NSP-Wisconsin filed a request with the PSCW to increase electric rates approximately $29.2 million, or 5.1 percent and natural gas rates approximately $8.0 million, or 6.6 percent effective Jan. 1, 2012. The rate filing is based on a 2012 forecast test year and includes a requested ROE of 10.75 percent, an equity ratio of 52.54 percent, an electric rate base of approximately $718 million and a natural gas rate base of $84 million.

In October 2011, the PSCW Staff filed testimony and recommended an electric rate increase of $18.1 million and a natural gas rate increase of $2.9 million, based on an ROE of 10.3 percent. Rebuttal testimony supporting NSP-Wisconsin’s recommendations was filed on Oct. 21, 2011.

Evidentiary hearings are scheduled for Nov. 2, 2011. NSP-Wisconsin anticipates a PSCW decision in the fourth quarter of 2011 with new rates effective Jan. 1, 2012.

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PSCo

Pending and Recently Concluded Regulatory Proceedings — CPUC

PSCo 2010 Gas Rate Case — In December 2010, PSCo filed a request with the CPUC to increase Colorado retail gas rates by $27.5 million on an annual basis. In March 2011, PSCo revised its requested rate increase to $25.6 million. The revised request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $1.1 billion and an equity ratio of 57.1 percent. PSCo proposed recovering $23.2 million of test year capital and operating and maintenance (O&M) expenses associated with several pipeline integrity costs plus an amortization of similar costs that have been accumulated and deferred since the last rate case in 2006. PSCo also proposed removing the earnings on gas in underground storage from base rates.

In August 2011, the CPUC approved a comprehensive settlement that PSCo reached with CPUC Staff and the Colorado Office of Consumer Counsel (OCC) to increase rates by $12.8 million, to institute rider recovery of future pipeline integrity costs, and to remove gas in underground storage from base rates and recover those costs in the Gas Cost Adjustment (GCA) rider. The GCA recovery of the return on gas in underground storage is expected to recover another $10 million of annual incremental revenue, subject to adjustment to actual costs. Rates were set on a test year ending June 30, 2011 with an equity ratio of 56 percent and an ROE of 10.1 percent.

New base rates and the GCA recovery went into effect in September 2011. The rider for pipeline integrity costs is expected to go into effect on Jan. 1, 2012 and is expected to recover an estimated $31.5 million of incremental revenue in 2012.

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

PSCo Wholesale Electric Rate Case — In February 2011, PSCo filed with the FERC to change Colorado wholesale electric rates to formula based rates with an expected annual increase of $16.1 million for 2011. The request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $407.4 million and an equity ratio of 57.1 percent. The formula rate would be estimated each year for the following year and then would be trued up to actual costs after the conclusion of the calendar year. A decision is expected in the first quarter of 2012.

Electric, Purchased Gas and Resource Adjustment Clauses

Renewable Energy Credit (REC) Sharing Settlement — In May 2010, the CPUC approved a settlement on the treatment of margins associated with sales of Colorado RECs that are bundled with energy into California. The settlement establishes a pilot program and defines certain margin splits during this pilot period. The settlement provides that annual margins would be shared based on the following allocations:

Margin	Customers			PSCo			Carbon Offsets
Less than $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. Margins associated with sales of unbundled stand-alone RECs without energy would be credited 100 percent to customers.

In May 2011, the CPUC determined that margin sharing on stand-alone REC transactions would be shared 20 percent to PSCo and 80 percent to customers beginning in 2011 and ultimately becoming 10 percent to PSCo and 90 percent to customers by 2014. The CPUC also approved a change to the treatment of REC trading margins that allows the customers’ share of the margins through the end of the pilot period, approximately $54 million, to be netted against the renewable energy standard adjustment (RESA) regulatory asset balance. In the second quarter of 2011, PSCo credited approximately $37 million against the RESA regulatory asset balance.

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In June 2011, PSCo filed an application for permanent treatment of Colorado RECs that are bundled with energy into California. The application is seeking margin sharing of 30 percent to PSCo and 70 percent to customers for deliveries outside of California and 40 percent to PSCo and 60 percent to customers for deliveries inside of California. PSCo also proposed that sales of RECs bundled with on-system energy be aggregated with other trading margins and shared 20 percent to PSCo and 80 percent to customers. In September 2011, parties filed answer testimony requesting the CPUC approve margin sharing of 8 percent to 25 percent to PSCo for deliveries outside of California and 8 percent to 35 percent for deliveries inside of California. Hearings were held in October 2011 and a decision is expected in the first quarter of 2012.

SPS

Pending and Recently Concluded Regulatory Proceedings — New Mexico Public Regulation Commission (NMPRC)

SPS New Mexico Electric Rate Case — In February 2011, SPS filed a request in New Mexico with the NMPRC seeking to increase New Mexico electric rates approximately $19.9 million. The rate filing was based on a 2011 test year adjusted for known and measurable changes for 2012, a requested ROE of 11.25 percent, an electric rate base of $390.3 million and an equity ratio of 51.11 percent.

In September 2011, the parties filed an unopposed black box settlement to resolve all issues in the case. If the settlement is approved by the NMPRC, base rates will increase by $13.5 million. SPS has agreed not to file another base rate case until Dec. 3, 2012 with new final rates from the result of such case not going into effect until Jan. 1, 2014 (Settlement Period), provided however, that SPS can request to implement interim rates if the NMPRC standard for interim rates is met. During the Settlement Period, rates are to remain fixed aside from the continued operation of the fuel adjustment clause and certain exceptions for energy efficiency, a rider for an approved renewable portfolio standard regulatory asset, and actual costs incurred for environmental regulations with an effective date after Dec. 31, 2010.

In October 2011, the NMPRC held hearings on the settlement. A decision by the NMPRC is expected by year-end and final rates are expected to be implemented effective Jan. 1, 2012.

6.	Commitments and Contingent Liabilities

Except to the extent noted below and in Note 5 to the consolidated financial statements in this Quarterly Report on Form 10-Q, the circumstances set forth in Notes 13, 14 and 15 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2010, 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 — The accounting guidance for consolidation of variable interest entities 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 enterprise is a variable interest entity’s primary beneficiary.

Purchased Power Agreements — Under certain purchased power agreements, NSP-Minnesota, PSCo and SPS purchase power from independent power producing entities that own natural gas or biomass fueled power plants for which the utility subsidiaries are required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase.

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 expenses, 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. Xcel Energy had approximately 3,973 megawatts (MW) and 4,101 MW of capacity under long-term purchased power agreements as of Sept. 30, 2011 and Dec. 31, 2010 with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2033.

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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 Inc. 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 do not consistently align with the partners’ proportional equity ownership. Xcel Energy Inc. 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 Inc. consolidates these limited partnerships in its consolidated financial statements.

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, 2011		Dec. 31, 2010
Current assets	$	3,711	$	3,794
Property, plant and equipment, net		95,618		97,602
Other noncurrent assets		8,267		8,236
Total assets	$	107,596	$	109,632

Current liabilities	$	13,400	$	11,884
Mortgages and other long-term debt payable		51,204		53,195
Other noncurrent liabilities		8,513		8,333
Total liabilities	$	73,117	$	73,412

Guarantees — Xcel Energy Inc. and its subsidiaries have provided guarantees and bond indemnities under specified agreements or transactions. The guarantees and bond indemnities issued by Xcel Energy Inc. guarantee payment or performance by its subsidiaries. As a result, Xcel Energy Inc.’s exposure under the guarantees and bond indemnities is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries limit exposure to a maximum amount stated in the guarantees and bond indemnities. As of Sept. 30, 2011 and Dec. 31, 2010, Xcel Energy Inc. and its subsidiaries had no assets held as collateral relating to its guarantees and bond indemnities.

The following table presents guarantees and bond indemnities issued and outstanding for Xcel Energy Inc.:

(Millions of Dollars)	Sept. 30, 2011		Dec. 31, 2010
Guarantees issued and outstanding	$	155.0	$	155.7
Known exposure under these guarantees		17.9		18.0
Bonds with indemnity protection		31.2		32.5

Environmental Contingencies

Xcel Energy Inc. 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 Inc. 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 — The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regarding the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances to the environment. 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 Inc. 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, 2011 and Dec. 31, 2010, the liability for the cost of remediating these sites was estimated to be $107.3 million and $104.0 million, respectively, of which $7.3 million and $5.7 million, respectively, was considered to be a current liability.

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MGP 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.

In 2002, the Ashland site was placed on the National Priorities List. In 2009, the Environmental Protection Agency (EPA) issued its proposed remedial action plan. The EPA issued its Record of Decision (ROD) in September 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 $83 million and $97 million. The EPA has stated that this cost estimate is expected to be within plus 50 percent to minus 30 percent of the actual project costs.

In April 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, responsible for future cleanup at the site. The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intended to conduct or pay for the cleanup. The special notice established a 60-day moratorium against enforcement action by the EPA. On June 30, 2011, NSP-Wisconsin submitted a settlement offer to EPA related to the future cleanup of the site and performance of a pilot study in Chequamegon Bay to demonstrate the effectiveness of a wet dredge full scale sediment remedy at the site. On July 14, 2011, the EPA informed NSP-Wisconsin and the other PRPs that it was rejecting all of their individual offers and that the EPA had determined it would not extend the enforcement moratorium by another 60 days, such that the EPA can now choose to initiate enforcement actions at any time. Despite this decision, the EPA also indicated a willingness to continue settlement negotiations with NSP-Wisconsin. Those settlement negotiations are ongoing.

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 negotiations or litigation with the EPA and other PRPs at the site are fully resolved. 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 potential remediation and design costs 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 incurred by other Wisconsin utilities for remediation of manufactured gas plants. 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. Under an existing PSCW policy with respect to recovery of remediation costs for manufactured gas plants, utilities have recovered costs amortized over a four- to six-year period. The PSCW has not allowed utilities to recover interest on the unamortized balance.

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.

Owen Park MGP Site — The Wisconsin Department of Natural Resources (WDNR) requested that NSP-Wisconsin investigate the Owen Park site on the west bank of the Chippewa River in Eau Claire, Wis. It is believed that this site was previously an MGP site prior to current ownership by the City of Eau Claire. The WDNR has indicated that it believes NSP-Wisconsin may have successor liability for the Owen Park site.

In response to the WDNR’s request, NSP-Wisconsin performed a site investigation, and has concluded that materials typically associated with the operation of MGPs are present in soils and groundwater at the site. NSP-Wisconsin has submitted a proposed remediation action plan to the WDNR for the remediation of the site. The ultimate scope and costs of such remediation will not be fully determinable until a remediation action plan is approved by the WDNR. NSP-Wisconsin has recorded a liability of $2.2 million based upon potential remediation, design and outside consultant costs.

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Asbestos Removal — Some of Xcel Energy’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. 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 14 of the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2010. 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 not expected to be material 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) Regulation — In December 2009, the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare. In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold.

GHG New Source Performance Standard Proposal — The EPA plans to propose GHG regulations applicable to emissions from new and existing power plants under the Clean Air Act (CAA). The EPA had planned to release its proposal in September 2011, but has delayed it without establishing a new proposal date.

Cross State Air Pollution Rule (CSAPR) — On July 7, 2011, the EPA issued its CSAPR. The rule, previously called the Clean Air Transport Rule (CATR), addresses long range transport of particulate matter and ozone by requiring reductions in sulfur dioxide (SO2) and nitrogen oxide (NOx) from utilities located in the eastern half of the U.S. For Xcel Energy, the rule applies to Minnesota, Wisconsin and Texas. The CSAPR sets more stringent requirements than the proposed CATR and, in contrast to that proposal, specifically requires plants in Texas to reduce their SO2 and annual NOx emissions. The rule creates an emissions trading program. Xcel Energy may comply by reducing emissions and/or purchasing allowances. The CSAPR is a final rule and requires compliance beginning in 2012.

At this time, Xcel Energy believes that the CSAPR will ultimately require the installation of additional emission controls on some of SPS’ coal-fired electric generating units. SPS is still evaluating compliance options, however SPS believes the cost of any required capital investment will be recoverable from customers. Because the CSAPR requires compliance in 2012, SPS will be required to take additional short-term action, including redispatching its system to reduce coal plant operating hours, in order to decrease emissions from its facilities prior to the installation of emission controls. Texas was not included in the annual SO2 and NOx reductions requirements of the proposed rule. Without additional notice, the EPA determined in the final CSAPR that Texas would be required to reduce SO2 emissions, comply with the annual NOx emission limits, and be in compliance beginning in 2012. Since the final CSAPR was published on Aug. 8, 2011, SPS has analyzed compliance scenarios and concluded that, unless a new CSAPR allowance market develops quickly, SPS would have to redispatch its system to run its natural gas plants as base load units. Additionally, SPS would have to substantially reduce coal plant operations in order to comply with the CSAPR using the emission allowances allocated to SPS by the EPA, which requires, for example, a 46 percent reduction in SO2 emissions in 2012. SPS has estimated that such a substantial change in operations could cost up to $250 million in 2012, mostly due to increased fuel costs, as well as increase risk to reliability on its system. SPS also expects that in order to comply with the CSAPR, its entire system will have to reduce NOx emissions by 33 percent in 2012. SPS expects it will be able to recover these costs through regulatory mechanisms and it does not expect a material impact on its results of operations.

On Oct. 6, 2011, the EPA proposed two relevant changes to revise the CSAPR. SPS’ initial analysis indicates that this proposed rule, if finalized, would not appreciably change the CSAPR’s adverse impact on SPS and its customers, because SPS is constrained by both NOx and SO2 emission reduction obligations under the rule. SPS remains concerned that the allowance market will not develop to the extent necessary to defray the cost and reliability risks associated with the CSAPR. SPS has preliminarily concluded that the proposal may reduce the cost of compliance by a modest amount if finalized, but it would not significantly alleviate the risks associated with the 2012 compliance date.

SPS filed two petitions with the EPA for reconsideration and stay of the CSAPR as it applies to the requirement for annual emission reductions in Texas. In addition, SPS filed a petition for review of the CSAPR with the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit) that challenges the inclusion of Texas in the CSAPR’s annual reduction programs and the 2012 compliance date. Along with the petition for review, SPS also filed a motion for stay of the CSAPR with the D.C. Circuit. SPS expects that the court will rule on the motion for stay by the end of 2011. Success in these legal actions could reduce SPS’ costs to comply with the CSAPR substantially. SPS expects it will be able to recover legal costs through regulatory mechanisms and it does not expect a material impact on its results of operations.

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To comply with the CSAPR in Minnesota, NSP-Minnesota currently intends to utilize a combination of emissions reductions through control technology upgrades at NSP-Minnesota’s Sherco plant, including the installation of a sparger system for SO2 control, at an estimated cost of $10 million total in 2012 and 2013, and system operating changes to the Black Dog and the Sherco plants. If available, NSP-Minnesota will also consider allowance purchases. In addition, NSP-Minnesota has filed a petition for reconsideration with the EPA and a petition for review of the CSAPR with the D.C. Circuit seeking the allocation of additional emission allowances to NSP-Minnesota. NSP-Minnesota contends that the EPA’s method of allocating allowances arbitrarily resulted in fewer allowances for its Riverside and High Bridge plants than should have been awarded to reflect their operations during the baseline period, which included coal-fired operations prior to their conversion to natural gas. If successful, additional allowances would reduce NSP-Minnesota’s costs to comply with the reductions imposed by the CSAPR.

To comply with the CSAPR in Wisconsin, NSP-Wisconsin currently intends to make a combination of system operating changes and allowance purchases, if available. NSP-Wisconsin estimates the cost of compliance to be $0.2 million, and it expects the cost of any required capital investment will be recoverable from customers.

Xcel Energy continues to evaluate its compliance strategy. Xcel Energy believes the cost of any required capital investment, allowance purchases or costs associated with redispatch will be recoverable from customers.

Clean Air Interstate Rule (CAIR) — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. In 2008, the D.C. Circuit vacated and remanded the CAIR, but subsequently allowed the CAIR to continue into effect pending the EPA’s adoption of a new rule that addressed the deficiencies found by the court. In 2011, the EPA finalized the CSAPR to replace CAIR beginning in 2012. The CAIR applies to Texas and Wisconsin. The CAIR does not apply in Minnesota because the court specifically found that the EPA had not adequately justified the application of the CAIR to Minnesota.

Under the CAIR’s cap and trade structure, companies 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. At Sept. 30, 2011, the estimated annual CAIR NOx allowance cost for SPS was $0.1 million. At Sept. 30, 2011, the estimated annual CAIR NOx allowance cost for NSP-Wisconsin was $0.1 million. At the end of 2011, the CAIR will end and compliance efforts will transition to the CSAPR beginning in 2012. No allowance trading is allowed between the CAIR and CSAPR programs.

Electric Generating Unit (EGU) Maximum Achievable Control Technology (MACT) Rule — In 2005, the EPA issued the Clean Air Mercury Rule (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.

In March 2011, the EPA issued the proposed EGU MACT designed to address emissions of mercury and other hazardous air pollutants for coal-fired utility units greater than 25 MW. The EPA has indicated that it intends to issue the final rule by December 2011. Xcel Energy anticipates that the EPA will require affected facilities to demonstrate compliance within three to four years. Xcel Energy believes these costs would be recoverable through regulatory mechanisms, and it does not expect a material impact on its results of operations.

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 the end of 2011. 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. The Pawnee mercury controls are included in the CACJA plan.

Minnesota Mercury Legislation — In 2006, the Minnesota legislature enacted the Mercury Emissions Reduction Act (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 continuous mercury emission monitoring systems at these generating facilities.

In November 2008, the MPUC approved 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 and at A.S. King in December 2010. In 2010, NSP-Minnesota collected the revenue requirements associated with these projects through the mercury cost reduction (MCR) rider. In the 2010 Minnesota electric general rate case, NSP-Minnesota proposed moving the costs of these projects into base rates as part of the interim rates effective on Jan. 2, 2011. Concurrent with the implementation of interim rates, the MCR rider was reduced to zero.

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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 October 2010, the MPUC approved the plan, which will require installation of mercury controls on Sherco Units 1 and 2 by the end of 2014. NSP-Minnesota has incurred $1.5 million in study costs to date and spent $0.6 million through Dec. 31, 2010 for testing and studying of technologies. At Sept. 30, 2011, the estimated annual testing and study cost is $0.5 million. NSP-Minnesota projects installation costs of $12.0 million for the units and O&M expense of $10.0 million per year beginning in 2014.

Industrial Boiler (IB) MACT Rules — In March 2011, the EPA finalized IB MACT rules to regulate boilers and process heaters fueled with coal, biomass and liquid fuels. The EPA has announced that it will be reconsidering portions of these rules. In its current form, the IB MACT rule would apply to NSP-Wisconsin’s Bay Front units 1 and 2. The estimated cost of $9.0 million per unit, which is currently targeted for 2014, is dependent on the outcome of the reconsideration proceedings to comply with these rules.

Regional Haze Rules — In 2005, the EPA finalized amendments to its regional haze rules regarding provisions that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S. Xcel Energy generating facilities in several states will be subject to BART requirements. Individual states are required to identify the facilities located in their states that will have to reduce SO2, NOx and particulate matter emissions under BART and then set emissions limits for those facilities.

PSCo

In 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. In January 2011, the Colorado Air Quality Commission approved a revised Regional Haze BART/Reasonable Further Progress state implementation plan (SIP) incorporating the Colorado CACJA emission reduction plan. In accordance with Colorado law, the SIP passed the Colorado general assembly, was signed by the governor and was submitted to the EPA. PSCo anticipates that for those plants included in the Colorado CACJA emission reduction plan, the SIP will satisfy regional haze requirements. The Colorado SIP, however, must be approved by the EPA. 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.

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 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 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 determination and proposed SO2 and NOx limits in the draft SIP that are equivalent to the reductions made under CAIR. Neither the MPCA nor the EPA has yet made a determination that the compliance with the CSAPR is better than BART or that compliance with the CSAPR will fulfill the obligation to comply with BART.

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. In June 2011, the EPA provided comments to the MPCA on the SIP, stating the EPA’s preliminary review indicates that SCR controls should be added to Sherco Units 1 and 2, and inviting further comment from the MPCA. It is not yet known what the final requirements of the SIP will be. Until the EPA takes final action on the SIP, the total cost of compliance cannot be estimated.

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Federal Clean Water Act (CWA Section 316 (b)) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. In April 2011, the EPA published the proposed rule that was modified to address earlier court decisions. The proposed rule sets prescriptive standards for minimization of aquatic species impingement but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. Xcel Energy provided comments to the proposed rule. Due to the uncertainty of the final regulatory requirements, 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 a decision on the plan by the end of 2011.

Proposed Coal Ash Regulation — Xcel Energy’s operations generate hazardous wastes that are subject to the Federal Resource Recovery and Conservation Act and comparable state laws that impose detailed requirements for handling, storage, treatment and disposal of hazardous waste. 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 hazardous or nonhazardous waste. Coal ash is currently exempt from hazardous waste regulation. If the EPA ultimately issues a final rule under which coal ash is regulated as hazardous waste, Xcel Energy’s costs associated with the management and disposal of coal ash would significantly increase, and the beneficial reuse of coal ash would be negatively impacted. The EPA has not announced a planned date for a final rule. 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 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 Generating 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. It is not known whether any costs would be incurred as a result of this notice.

Cunningham Compliance Order — In February 2010, SPS received a draft compliance order from the New Mexico Environment Department (NMED) for Cunningham Station. In the draft order, the NMED alleges that Cunningham exceeded its permit limits for NOx and failed to report these exceedances as required by its permit. Prior to the formal administrative hearings, SPS negotiated a penalty of $0.8 million. The final agreement is currently being completed by both parties.

NSP-Minnesota NOV — In June 2011, NSP-Minnesota received an NOV from the EPA alleging violations of the NSR requirements of the CAA at the Sherco plant and Black Dog plant in Minnesota. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid 2000s should have required a permit under the NSR process. NSP-Minnesota believes it has acted in full compliance with the CAA and NSR process. NSP-Minnesota 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. NSP-Minnesota disagrees with the assertions contained in the NOV and intends to vigorously defend its position. It is not known whether any costs would be incurred as a result of this notice.

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. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material effect on Xcel Energy’s financial position and results of operations.

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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 for the Southern District of New York against the following utilities, including Xcel Energy, to force reductions in carbon dioxide (CO2) emissions: American Electric Power Co., Southern Co., Cinergy Corp. (merged into Duke Energy Corporation) 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. In September 2005, the court granted plaintiffs’ motion to dismiss on constitutional grounds. In August 2010, this decision was reversed by the Second Circuit and was appealed to the U.S. Supreme Court. In June 2011, the Supreme Court issued a ruling reversing the Second Circuit’s decision, thereby dismissing plaintiffs’ federal claims and remanding the case for further proceedings regarding the state law claims. In September 2011, plaintiffs submitted a letter to the Second Circuit seeking to voluntarily dismiss the complaint.

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 utility, 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 in June 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. Oral arguments are set for Nov. 28, 2011. It is unknown when the Ninth Circuit will render a final opinion. The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina. Plaintiffs’ alleged relocation is estimated to cost between $95 million to $400 million. No accrual has been recorded for this matter.

Comer vs. Xcel Energy Inc. et al. — On May 27, 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in U.S. District Court in Mississippi. The complaint alleges defendants’ CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property. Plaintiffs base their claims on public and private nuisance, trespass and negligence. Among the defendants named in the complaint are Xcel Energy Inc., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota. The amount of damages claimed by plaintiffs is unknown. It is believed that this lawsuit is without merit. No accrual has been recorded for this matter.

Employment, Tort and Commercial Litigation

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. This decision was subsequently affirmed by the Colorado Supreme Court in June 2011. On Sept. 16, 2011, Qwest filed a petition for a Writ of Certiorari with the U.S. Supreme Court. No accrual has been recorded for this matter.

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, alleged, among other things, that PSCo mismanaged the construction of Comanche Unit 3. Shaw further claimed that this alleged mismanagement caused delays and damages. The complaint also alleged that Xcel Energy Inc. and related entities guaranteed Shaw $10 million in future profits under the terms of a 2003 settlement agreement. Shaw alleged that it will not receive the $10 million to which it is entitled. Accordingly, Shaw sought an amount up to $10 million related to the 2003 settlement agreement. In total, Shaw sought approximately $144 million in damages.

PSCo denied 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 failed to discharge its contractual obligations and caused delays, and that PSCo is entitled to liquidated damages and excess costs incurred. In total, PSCo sought 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 denied the merits of this claim.

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In November 2010, a jury returned a verdict on the issues raised in the first complaint that awarded damages to Shaw and to PSCo. Specifically, the jury awarded a total of $84.5 million to Shaw but also awarded $70.0 million to PSCo for damages related to its counterclaims, for a net verdict to Shaw in the amount of $14.5 million. Shaw subsequently filed post trial motions, which the court denied. In March 2011, Shaw filed its notice of appeal on all issues raised at trial and in post-trial motions. PSCo filed a conditional cross-appeal in April 2011. This litigation is not expected to have a material effect on Xcel Energy’s consolidated results of operations, cash flows or financial position.

Merricourt Wind Project Litigation — On April 1, 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota. NSP-Minnesota’s decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact. NSP-Minnesota also terminated the agreements due to enXco’s nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011. As a result, NSP-Minnesota recorded a $101 million deposit in the first quarter 2011, which was collected in April 2011. On May 5, 2011, NSP-Minnesota filed a declaratory judgment action in U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements. On that same day, enXco also filed a separate lawsuit in the same court seeking, among other things, in excess of $240 million for an alleged breach of contract. NSP-Minnesota believes enXco’s lawsuit is without merit and has filed a motion to dismiss. On Sept. 16, 2011, the U.S. District Court denied the motion to dismiss. The trial is set to begin in late 2012 or early 2013. No accrual has been recorded for this matter.

Nuclear Power Operations and Waste Disposal

Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the U.S. 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 U.S. 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 February 2008, the U.S. 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.

In August 2007, NSP-Minnesota filed a second complaint against the U.S. 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 claimed damages for the period Jan. 1, 2005 through Dec. 31, 2008, which included 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.

In July 2011, the U.S. and NSP-Minnesota executed a settlement agreement resolving both lawsuits, providing an initial $100 million payment from the U.S. to NSP-Minnesota, and providing a method by which NSP-Minnesota can recover its spent fuel storage costs through 2013, currently estimated to be an additional $100 million. The settlement does not address costs for used fuel storage after 2013; such costs could be the subject of future litigation. NSP-Minnesota received the initial $100 million payment in August 2011, of which $15 million is expected to be allocated to NSP-Wisconsin through the interchange agreement. NSP-Minnesota will make the appropriate regulatory filings to address the best means of returning these settlement amounts to ratepayers and to deal with costs of litigation. As of Sept. 30, 2011, the payment received from the DOE has been recorded as restricted cash and a regulatory liability.

7.	Borrowings and Other Financing Instruments

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utilities. NSP-Wisconsin does not participate in the money pool. Xcel Energy Inc. 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 Xcel Energy Inc. The money pool investments and borrowings are eliminated upon consolidation.

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Commercial Paper — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities. Commercial paper outstanding for Xcel Energy was as follows:

(Millions of Dollars)	Three Months Ended Sept. 30, 2011			Twelve Months Ended Dec. 31, 2010
Borrowing limit	$	2,450		$	2,177
Amount outstanding at period end		50			466
Average amount outstanding		477			263
Maximum amount outstanding		824			653
Weighted average interest rate, computed on a daily basis		0.36	%		0.36	%
Weighted average interest rate at period end		0.34			0.40

Credit Facilities — In order to use their commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit agreements.

During March 2011, NSP-Minnesota, NSP-Wisconsin, PSCo, SPS and Xcel Energy Inc. executed new four-year credit agreements. The total size of the credit facilities is $2.45 billion and each credit facility terminates in March 2015. Xcel Energy Inc. and its utility subsidiaries have the right to request an extension of the revolving termination date for two additional one-year periods, subject to majority bank group approval.

The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Other features of the credit facilities include:

Each of the credit facilities, other than NSP-Wisconsin’s, may be increased by up to $200 million for Xcel Energy Inc., $100 million each for NSP-Minnesota and PSCo, and $50 million for SPS.

Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio of each entity be less than or equal to 65 percent. Each entity was in compliance at Sept. 30, 2011 as evidenced by the table below:

	Debt-to-Total Capitalization Ratio
NSP-Minnesota	48	%
PSCo	45
SPS	48
Xcel Energy	54
NSP-Wisconsin	48

If Xcel Energy Inc. or any of its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.

The Xcel Energy Inc. credit facility has a cross-default provision that provides Xcel Energy Inc. will be in default on its borrowings under the facility if it or any of its subsidiaries, except NSP-Wisconsin as long as its total assets do not comprise more than 15 percent of Xcel Energy’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million.

The interest rates under these lines of credit are based on the Eurodollar rate or an alternate base rate, plus a borrowing margin of 0 to 200 basis points per year based on the applicable credit ratings.

The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the lines of credit at a range of 10 to 35 basis points per year.

NSP-Wisconsin’s intercompany borrowing arrangement with NSP-Minnesota was subsequently terminated.

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At Sept. 30, 2011, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available:

(Millions of Dollars)	Credit Facility		Drawn (a)		Available
Xcel Energy Inc.	$	800.0	$	22.1	$	777.9
PSCo		700.0		4.8		695.2
NSP-Minnesota		500.0		7.1		492.9
SPS		300.0		-		300.0
NSP-Wisconsin		150.0		28.0		122.0
Total	$	2,450.0	$	62.0	$	2,388.0

(a)	Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding at Sept. 30, 2011 and Dec. 31, 2010.

Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At Sept. 30, 2011 and Dec. 31, 2010, there were $12.0 million and $10.1 million of letters of credit outstanding, respectively. An additional $1.1 million of letters of credit not issued under the credit facilities were outstanding at Sept. 30, 2011 and Dec. 31, 2010. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

Long-Term Borrowings

In September 2011, Xcel Energy Inc. issued $250 million of 4.80 percent senior unsecured notes due Sept. 15, 2041. Xcel Energy Inc. added the net proceeds from the sale of the notes to its general funds and used the proceeds to repay short-term debt and for general corporate purposes.

In August 2011, PSCo issued $250 million of 4.75 percent first mortgage bonds due Aug. 15, 2041. PSCo used a portion of the net proceeds from the sale of the first mortgage bonds to repay short-term debt borrowings incurred to fund daily operational needs. The balance of the net proceeds was used for general corporate purposes.

In August 2011, SPS issued $200 million of 4.50 percent first mortgage bonds due Aug. 15, 2041. SPS used a portion of the net proceeds from the sale of the first mortgage bonds to repay short-term debt borrowings incurred to fund daily operational needs and to redeem $57.3 million of the outstanding 5.75 percent Pollution Control Revenue Refunding Bonds due Sept. 1, 2016. The balance of the net proceeds was used for general corporate purposes.

8.	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with discounted cash flow or option pricing models using highly observable inputs.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

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Specific valuation methods include the following:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds and international equity funds are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of each fund, in order to determine a per share market value. The investments in commingled funds and international equity funds may be redeemed for net asset value.

Investments in debt securities — Debt securities are primarily priced using recent trades and observable spreads from benchmark interest rates for similar securities, except for asset-backed and mortgage-backed securities, which also require significant, subjective risk-based adjustments to the interest rate used to discount expected future cash flows, which include estimated principal prepayments. Therefore, fair value measurements for asset-backed and mortgage-backed securities have been assigned a Level 3.

Interest rate derivatives — The fair value of interest rate derivatives are based on broker quotes utilizing market interest rate curves.

Commodity derivatives — The methods utilized to measure the fair value of commodity derivatives include the use of forward prices and volatilities to value commodity forwards and options. Levels are assigned to these fair value measurements based on the significance of the use of subjective forward price and volatility forecasts for commodities and delivery locations with limited observability, or the significance of contractual settlements that extend to periods beyond those readily observable on active exchanges or quoted by brokers. Electric commodity derivatives include financial transmission rights (FTRs), for which fair value is determined using complex predictive models and inputs including forward commodity prices as well as subjective forecasts of retail and wholesale demand, generation and resulting transmission system congestion. Given the limited observability of management’s forecasts for several of these inputs, fair value measurements for FTRs have been assigned a Level 3.

Xcel Energy continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of Xcel Energy’s own credit risk when determining the fair value of commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities presented in the consolidated balance sheets.

Non-Derivative Instruments Fair Value Measurements

The Nuclear Regulatory Commission (NRC) requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and Prairie Island nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities, and other investments - all classified as available-for-sale securities under the applicable accounting guidance. NSP-Minnesota plans to reinvest matured securities until decommissioning begins.

NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.

Unrealized gains for the decommissioning fund were $54.4 million and $82.5 million at Sept. 30, 2011 and Dec. 31, 2010, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $140.9 million and $65.2 million at Sept. 30, 2011 and Dec. 31, 2010, respectively.

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The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments recurring fair value measurements, the nuclear decommissioning fund investments, at Sept. 30, 2011 and Dec. 31, 2010:

	Sept. 30, 2011
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	77,875	$	75,370	$	2,505	$	-	$	77,875
Commingled funds		296,629		-		267,511		-		267,511
International equity funds		63,781		-		56,956		-		56,956
Debt securities:
Government securities		163,744		-		168,798		-		168,798
U.S. corporate bonds		174,314		-		176,450		-		176,450
Foreign securities		35,434		-		35,558		-		35,558
Municipal bonds		43,652		-		46,229		-		46,229
Asset-backed securities		10,251		-		-		10,246		10,246
Mortgage-backed securities		51,674		-		-		54,815		54,815
Equity securities:
Common stock		440,855		377,253		-		-		377,253
Total	$	1,358,209	$	452,623	$	754,007	$	65,061	$	1,271,691

(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $95.5 million of equity investments in unconsolidated subsidiaries and $32.3 million of miscellaneous investments.

	Dec. 31, 2010
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	83,837	$	76,281	$	7,556	$	-	$	83,837
Commingled funds		131,000		-		133,080		-		133,080
International equity funds		54,561		-		58,584		-		58,584
Debt securities:
Government securities		146,473		-		146,654		-		146,654
U.S. corporate bonds		279,028		-		288,304		-		288,304
Foreign securities		1,233		-		1,581		-		1,581
Municipal bonds		100,277		-		97,557		-		97,557
Asset-backed securities		32,558		-		-		33,174		33,174
Mortgage-backed securities		68,072		-		-		72,589		72,589
Equity securities:
Common stock		436,334		435,270		-		-		435,270
Total	$	1,333,373	$	511,551	$	733,316	$	105,763	$	1,350,630

(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $97.6 million of equity investments in unconsolidated subsidiaries and $28.2 million of miscellaneous investments.

Table of Contents

The following tables present the changes in Level 3 nuclear decommissioning fund investments:

	Three Months Ended Sept. 30,
	2011						2010
	Mortgage-			Asset-			Mortgage-			Asset-
	Backed			Backed			Backed			Backed
(Thousands of Dollars)	Securities			Securities			Securities			Securities
Balance at July 1	$	62,271		$	21,004		$	65,059		$	40,067
Purchases		1,972			9,496			-			-
Settlements		(8,978	)		(19,443	)		(1,949	)		(5,744	)
(Losses) gains recorded as regulatory assets and liabilities		(450	)		(811	)		1,286			171
Balance at Sept. 30	$	54,815		$	10,246		$	64,396		$	34,494

	Nine Months Ended Sept. 30,
	2011						2010
	Mortgage-			Asset-			Mortgage-			Asset-
	Backed			Backed			Backed			Backed
(Thousands of Dollars)	Securities			Securities			Securities			Securities
Balance at Jan. 1	$	72,589		$	33,174		$	81,189		$	11,918
Purchases		101,037			10,252			46,477			36,042
Settlements		(117,435	)		(32,559	)		(68,124	)		(13,853	)
(Losses) gains recorded as regulatory assets and liabilities		(1,376	)		(621	)		4,854			387
Balance at Sept. 30