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 June 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 £

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). £Yes 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 July 19, 2011
Common Stock, $2.50 par value		484,557,036 shares

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	38
	Item 3 —	Quantitative and Qualitative Disclosures about Market Risk	58
	Item 4 —	Controls and Procedures.	58
PART II		OTHER INFORMATION	58
	Item 1 —	Legal Proceedings.	58
	Item 1A —	Risk Factors	58
	Item 6 —	Exhibits	60
SIGNATURES			61
		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. Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado, a Colorado corporation (PSCo); and Southwestern Public Service Company, a New Mexico corporation (SPS). Additional information on the wholly owned subsidiaries is available on various filings with the Securities and Exchange Commission (SEC).

Table of Contents

PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Operating revenues
Electric	$	2,128,397		$	2,040,702		$	4,158,369		$	4,036,294
Natural gas		291,538			249,410			1,056,887			1,039,560
Other		18,287			17,652			39,506			39,372
Total operating revenues		2,438,222			2,307,764			5,254,762			5,115,226

Operating expenses
Electric fuel and purchased power		989,413			986,088			1,921,241			1,974,566
Cost of natural gas sold and transported		163,056			126,963			706,432			708,076
Cost of sales — other		6,891			4,704			14,946			12,396
Other operating and maintenance expenses		532,170			516,640			1,042,197			997,613
Conservation and demand side management program expenses		65,497			55,551			140,795			113,590
Depreciation and amortization		229,264			211,506			453,987			417,632
Taxes (other than income taxes)		92,489			81,008			189,059			162,384
Total operating expenses		2,078,780			1,982,460			4,468,657			4,386,257

Operating income		359,442			325,304			786,105			728,969

Other income, net		979			1,709			5,745			2,684
Equity earnings of unconsolidated subsidiaries		7,677			7,362			15,390			14,763
Allowance for funds used during construction — equity		13,606			12,996			26,850			26,286

Interest charges and financing costs

Interest charges — includes other financing costs of $6,185, $5,146, $11,445 and $10,157, respectively		146,338			141,455			290,692			285,285
Allowance for funds used during construction — debt		(7,838	)		(6,575	)		(15,274	)		(14,312	)
Total interest charges and financing costs		138,500			134,880			275,418			270,973

Income from continuing operations before income taxes		243,204			212,491			558,672			501,729
Income taxes		84,533			76,866			196,534			198,764
Income from continuing operations		158,671			135,625			362,138			302,965
Income from discontinued operations, net of tax		91			4,151			193			3,929
Net income		158,762			139,776			362,331			306,894
Dividend requirements on preferred stock		1,060			1,060			2,120			2,120
Earnings available to common shareholders	$	157,702		$	138,716		$	360,211		$	304,774

Weighted average common shares outstanding:
Basic		484,918			460,041			484,283			459,483
Diluted		485,241			460,432			484,775			460,068

Earnings per average common share — basic:
Income from continuing operations	$	0.33		$	0.29		$	0.74		$	0.65
Income from discontinued operations		-			0.01			-			0.01
Earnings per share	$	0.33		$	0.30		$	0.74		$	0.66

Earnings per average common share — diluted:
Income from continuing operations	$	0.33		$	0.29		$	0.74		$	0.65
Income from discontinued operations		-			0.01			-			0.01
Earnings per share	$	0.33		$	0.30		$	0.74		$	0.66

Cash dividends declared per common share	$	0.26		$	0.25		$	0.51		$	0.50

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)

	Six Months Ended June 30,
	2011			2010

Operating activities
Net income	$	362,331		$	306,894
Remove income from discontinued operations		(193	)		(3,929	)
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		463,013			421,820
Conservation and demand side management program amortization		6,078			15,514
Nuclear fuel amortization		43,732			49,551
Deferred income taxes		197,637			171,260
Amortization of investment tax credits		(3,160	)		(3,188	)
Allowance for equity funds used during construction		(26,850	)		(26,286	)
Equity earnings of unconsolidated subsidiaries		(15,390	)		(14,763	)
Dividends from unconsolidated subsidiaries		16,931			15,791
Share-based compensation expense		20,299			16,470
Net realized and unrealized hedging and derivative transactions		16,802			(21,374	)
Changes in operating assets and liabilities:
Accounts receivable		38,914			73,118
Accrued unbilled revenues		117,836			140,035
Inventories		76,028			101,822
Other current assets		52,397			29,703
Accounts payable		32,116			(226,436	)
Net regulatory assets and liabilities		(41,888	)		27,643
Other current liabilities		(78,110	)		(139,252	)
Pension and other employee benefit obligations		(131,892	)		(7,169	)
Change in other noncurrent assets		13,119			1,128
Change in other noncurrent liabilities		(36,634	)		(15,137	)
Net cash provided by operating activities		1,123,116			913,215

Investing activities
Utility capital/construction expenditures		(1,122,269	)		(967,331	)
Merricourt refund		101,261			-
Merricourt deposit		(90,833	)		-
Allowance for equity funds used during construction		26,850			26,286
Purchase of investments in external decommissioning fund		(1,226,504	)		(3,001,198	)
Proceeds from the sale of investments in external decommissioning fund		1,226,491			3,006,616
Investment in WYCO Development LLC		(961	)		(2,905	)
Change in restricted cash		46			(44	)
Other investments		(3,964	)		4,150
Net cash used in investing activities		(1,089,883	)		(934,426	)

Financing activities
Proceeds from (repayment of) short-term borrowings, net		189,600			(330,000	)
Proceeds from issuance of long-term		-			544,205
Repayment of long-term debt, including reacquisition premiums		(1,741	)		(25,860	)
Proceeds from issuance of common stock		3,789			4,294
Dividends paid		(231,715	)		(212,387	)
Net cash used in financing activities		(40,067	)		(19,748	)

Net decrease in cash and cash equivalents		(6,834	)		(40,959	)
Cash and cash equivalents at beginning of period		108,437			115,648
Cash and cash equivalents at end of period	$	101,603		$	74,689
Supplemental disclosure of cash flow information:
Cash paid for interest, net of amounts capitalized	$	(266,559	)	$	(254,113	)
Cash received (paid) for income taxes, net		54,993			(7,831	)
Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable	$	120,558		$	53,871
Issuance of common stock for reinvested dividends and 401(k) plans	$	37,680		$	32,261

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands of dollars)

	June 30, 2011			Dec. 31, 2010
Assets
Current assets
Cash and cash equivalents	$	101,603		$	108,437
Accounts receivable, net		679,560			718,474
Accrued unbilled revenues		590,855			708,691
Inventories		484,772			560,800
Regulatory assets		381,457			388,541
Derivative instruments		53,832			54,079
Prepayments and other		186,884			193,621
Total current assets		2,478,963			2,732,643

Property, plant and equipment, net		21,513,539			20,663,082

Other assets
Nuclear decommissioning fund and other investments		1,517,058			1,476,435
Regulatory assets		2,160,780			2,151,460
Derivative instruments		169,067			184,026
Other		163,817			180,044
Total other assets		4,010,722			3,991,965
Total assets	$	28,003,224		$	27,387,690

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	53,927		$	55,415
Short-term debt		656,000			466,400
Accounts payable		957,521			979,750
Regulatory liabilities		170,655			156,038
Taxes accrued		189,564			254,320
Accrued interest		165,313			163,907
Dividends payable		127,040			122,847
Derivative instruments		39,990			61,745
Other		278,749			276,111
Total current liabilities		2,638,759			2,536,533

Deferred credits and other liabilities
Deferred income taxes		3,665,418			3,390,027
Deferred investment tax credits		89,777			92,937
Regulatory liabilities		1,143,485			1,179,765
Asset retirement obligations		1,277,785			969,310
Derivative instruments		272,481			285,986
Customer advances		258,161			269,087
Pension and employee benefit obligations		828,500			962,767
Other		225,757			249,635
Total deferred credits and other liabilities		7,761,364			7,399,514

Commitments and contingent liabilities
Capitalization
Long-term debt		9,263,556			9,263,144
Preferred stockholders' equity		104,980			104,980
Common stock – $2.50 par value per share		1,211,356			1,205,834
Additional paid in capital		5,261,687			5,229,075
Retained earnings		1,812,505			1,701,703
Accumulated other comprehensive loss		(50,983	)		(53,093	)
Total common stockholders' equity		8,234,565			8,083,519
Total liabilities and equity	$	28,003,224		$	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 June 30, 2011 and 2010
Balance at March 31, 2010		459,215	$	1,148,038	$	4,784,152	$	1,472,308		$	(48,627	)	$	7,355,871
Net income								139,776						139,776
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $321											456			456
Net derivative instrument fair value changes, net of tax of $(2,725)											(3,807	)		(3,807	)
Unrealized gain - marketable securities, net of tax of $(74)											(107	)		(107	)
Comprehensive income for the period														136,318
Dividends declared:
Cumulative preferred stock								(1,060	)					(1,060	)
Common stock								(117,027	)					(117,027	)
Issuances of common stock		412		1,031		7,612								8,643
Share-based compensation						9,077								9,077
Balance at June 30, 2010		459,627	$	1,149,069	$	4,800,841	$	1,493,997		$	(52,085	)	$	7,391,822

Balance at March 31, 2011		484,165	$	1,210,411	$	5,241,533	$	1,781,386		$	(51,847	)	$	8,181,483
Net income								158,762						158,762
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $525											754			754
Net derivative instrument fair value changes, net of tax of $100											110			110
Comprehensive income for the period														159,626
Dividends declared:
Cumulative preferred stock								(1,060	)					(1,060	)
Common stock								(126,583	)					(126,583	)
Issuances of common stock		378		945		8,072								9,017
Share-based compensation						12,082								12,082
Balance at June 30, 2011		484,543	$	1,211,356	$	5,261,687	$	1,812,505		$	(50,983	)	$	8,234,565

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
Six Months Ended June 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								306,894						306,894
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $616											875			875
Net derivative instrument fair value changes during the period, net of tax of $(2,265)											(3,155	)		(3,155	)
Unrealized gain - marketable securities, net of tax of $(66)											(96	)		(96	)
Comprehensive income for the period														304,518
Dividends declared:
Cumulative preferred stock								(2,120	)					(2,120	)
Common stock								(229,978	)					(229,978	)
Issuances of common stock		2,118		5,296		15,633								20,929
Share-based compensation						15,228								15,228
Balance at June 30, 2010		459,627	$	1,149,069	$	4,800,841	$	1,493,997		$	(52,085	)	$	7,391,822

Balance at Dec. 31, 2010		482,334	$	1,205,834	$	5,229,075	$	1,701,703		$	(53,093	)	$	8,083,519
Net income								362,331						362,331
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $1,076											1,548			1,548
Net derivative instrument fair value changes during the period, net of tax of $392											512			512
Unrealized loss - marketable securities, net of tax of $35											50			50
Comprehensive income for the period														364,441
Dividends declared:
Cumulative preferred stock								(2,120	)					(2,120	)
Common stock								(249,409	)					(249,409	)
Issuances of common stock		2,209		5,522		9,724								15,246
Share-based compensation						22,888								22,888
Balance at June 30, 2011		484,543	$	1,211,356	$	5,261,687	$	1,812,505		$	(50,983	)	$	8,234,565

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 June 30, 2011 and Dec. 31, 2010; the results of its operations and changes in stockholders’ equity for the three and six months ended June 30, 2011 and 2010; and its cash flows for the six months ended June 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 June 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 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 guidance to have a material impact on its consolidated financial statements.

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3.	Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2011			Dec. 31, 2010
Accounts receivable, net
Accounts receivable	$	730,694		$	773,037
Less allowance for bad debts		(51,134	)		(54,563	)
	$	679,560		$	718,474
Inventories
Materials and supplies	$	204,008		$	196,081
Fuel		180,788			188,566
Natural gas		99,976			176,153
	$	484,772		$	560,800
Property, plant and equipment, net
Electric plant	$	26,059,167		$	24,993,582
Natural gas plant		3,520,658			3,463,343
Common and other property		1,586,265			1,555,287
Plant to be retired (a)		199,315			236,606
Construction work in progress		1,143,591			1,186,433
Total property, plant and equipment		32,508,996			31,435,251
Less accumulated depreciation		(11,378,696	)		(11,068,820	)
Nuclear fuel		1,968,017			1,837,697
Less accumulated amortization		(1,584,778	)		(1,541,046	)
	$	21,513,539		$	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 2006 federal income tax return expired in August 2010. The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return expires in September 2011. The Internal Revenue Service (IRS) commenced an examination of tax years 2008 and 2009 in the third quarter of 2010. As of June 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 June 30, 2011, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions are as follows:

State		Year
Colorado		2006
Minnesota		2007
Texas		2006
Wisconsin		2006

As of June 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)	June 30, 2011		Dec. 31, 2010
Unrecognized tax benefit — Permanent tax positions	$	6.8	$	5.9
Unrecognized tax benefit — Temporary tax positions		34.0		34.6
Unrecognized tax benefit balance	$	40.8	$	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)		June 30, 2011				Dec. 31, 2010
NOL and tax credit carryforwards		$	(38.3	)		$	(38.0	)

The increase in the unrecognized tax benefit balance of $0.1 million from March 31, 2011 to June 30, 2011 and $0.3 million from Dec. 31, 2010 to June 30, 2011 was due primarily to the addition of uncertain tax positions related to current and prior years’ activity. Xcel Energy’s amount of unrecognized tax benefits 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 up to approximately $27 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 June 30, 2011 and Dec. 31, 2010 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 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. The rate filing is 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. NSP-Minnesota requested an additional increase of $48.3 million or 1.81 percent effective Jan. 1, 2012, to address certain known and measurable cost increases in 2012.

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 May 2011, NSP-Minnesota revised its rate increase request to approximately $126.4 million or 4.7 percent for 2011, largely due to a revised requested ROE of 10.85 percent. NSP-Minnesota also reduced its requested increase for 2012 to $44.7 million. The Department of Energy Resource (DOER) (formerly the Office of Energy Security or OES) recommended a $58 million rate increase, based on a 10.37 percent ROE and a $31 million adjustment for income taxes related to bonus depreciation. The Office of Attorney General (OAG) and the Xcel Large Industrial Group recommended a rate reduction and refund of depreciation reserves and reductions to or elimination of incentive compensation costs. The OAG recommended refunding the liability associated with retiree medical benefits.

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At the hearings in June 2011, NSP-Minnesota resolved differences with the DOER on income taxes and sales forecast. NSP-Minnesota also made an adjustment to bad debt and incentive compensation expense. As a result of these adjustments, NSP-Minnesota revised its requested rate increase to $122.8 million. The DOER revised its recommended rate increase to approximately $84.7 million, reflecting these same changes. The primary differences between the NSP-Minnesota requested rate increase and the DOER updated recommendation are associated with the ROE and incentive compensation issues. The DOER recommended an additional rate increase of $34 million in 2012. In the second quarter of 2011, NSP-Minnesota recorded a provision for revenue subject to refund of approximately $15 million, which should be sufficient to address an outcome that is more consistent with the DOER position than NSP-Minnesota’s position on various issues. NSP-Minnesota cannot predict the ultimate outcome of this pending regulatory proceeding. The MPUC decision is expected in the fourth quarter of 2011.

Electric, Purchased Gas and Resource Adjustment Clauses

Conservation Improvement Program (CIP) Rider — CIP expenses are recovered through a charge embedded in base rates and a rider that is adjusted annually. Under the 2010 electric CIP rider request filed in October 2010, NSP-Minnesota estimates recovery of $66.7 million through the rider during the November 2010 to September 2011 timeframe. This is in addition to an expected $48.1 million recovered through the conservation cost recovery charge component of base rates. NSP-Minnesota estimates recovery of approximately $18.6 million through the natural gas CIP rider filed in November 2010, during the December 2010 to September 2011 timeframe. This is in addition to an expected $3.0 million recovered through the conservation cost recovery charge component of base rates. Assuming MPUC approval, NSP-Minnesota estimates it will recover a total of approximately $136.4 million associated with CIP programs in 2011.

In April 2011, NSP-Minnesota filed its annual rider petitions requesting recovery of approximately $84.8 million of electric CIP expenses and financial incentives and $4.5 million of natural gas CIP expenses and financial incentives to be recovered during the October 2011 through September 2012 timeframe. This proposed recovery through the riders is in addition to an estimated $52.6 million and $3.8 million to be recovered through the electric and gas conservation cost recovery charge component of base rates, respectively. Assuming MPUC approval, NSP-Minnesota estimates it will recover a total of approximately $145.7 million associated with CIP programs in 2012.

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, RDF grant project payments, and RDF program administrative costs. In October 2010, NSP-Minnesota filed its annual request to recover $19.2 million in expenses for 2011. In May 2011, the MPUC approved recovery of the costs requested.

Annual Automatic Adjustment Report for 2009/2010 — In September 2010, NSP-Minnesota filed its annual electric and natural gas automatic adjustment reports for July 1, 2009 through June 30, 2010. During that time period, $749.5 million in fuel and purchased energy costs were recovered from Minnesota electric customers through the fuel clause adjustment. In addition, approximately $354.5 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 report in June 2011, and the report is pending MPUC action. The electric report is pending DOER comments and MPUC action.

The MPUC approved the 2008/2009 gas annual automatic adjustment report in March 2011. Approval of the 2008/2009 electric report is pending DOER comments and MPUC action.

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. 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. NSP-Minnesota requested an additional increase of $4.2 million, or 2.6 percent, effective Jan. 1, 2012, to address certain known and measurable cost increases in 2012.

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.

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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, which is anticipated in the first quarter of 2012. The remaining schedule is listed below:

Intervenor direct testimony due Aug. 18, 2011;

Rebuttal testimony due Sept. 20, 2011; and

Evidentiary hearings due Oct. 18-21, 2011.

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. Net of current automatic recovery mechanisms, the requested increase was $13.9 million. 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 life cycle management and enhanced power uprate project that is not reflected in the test year.

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, and an equity ratio of 52.54 percent. The rate base in 2012 is forecast to be approximately $718 million for the electric utility and $84 million for the natural gas utility. A PSCW decision is anticipated in the fourth quarter of 2011.

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 10.90 percent ROE, a rate base of $1.1 billion and an equity ratio of 57.10 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 May 2011, PSCo filed a comprehensive settlement with CPUC Staff and the Colorado Office of Consumer Counsel (OCC) to increase rates by $10.9 million, to institute rider recovery of future integrity management costs, and to remove 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 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 are expected to go into effect in September 2011. The rider for integrity management costs is expected to go into effect on Jan. 1, 2012 and is expected to recover an estimated $13 million of incremental revenue in 2012. In July 2011, the presiding hearing commissioner approved the settlement with certain modifications and PSCo subsequently filed exceptions to the recommended decision.

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

PSCo Wholesale Rate Case — In February 2011, PSCo filed a request with the FERC to change Colorado wholesale electric customer rates to formula based rates with an expected increase of $16.1 million annually for 2011. The request was based on a 2011 forecast test year, a 10.9 percent ROE, a wholesale rate base of $407.4 million and an equity ratio of 57.1 percent. Under the proposal, the formula rate would be estimated annually and then would be trued up to actual costs after the conclusion of the year. The primary drivers of the revenue deficiency are the recently acquired Blue Spruce Energy Center and Rocky Mountain Energy Center generating units, as well as the costs of early retirement of certain coal plants under the CACJA emissions reduction plan, all of which were approved by the CPUC in late 2010. In April 2011, the FERC suspended the effective date five months, allowing the rates to be placed into effect on Sept. 10, 2011, subject to refund and set the request for settlement procedures.

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 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. At June 30, 2011, PSCo credited approximately $37 million against the RESA regulatory asset balance.

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. The CPUC has indicated a desire to expedite the matter and a decision is expected in the fourth quarter of 2011.

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 is 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. Rates are expected to go into effect during the first quarter of 2012.

The New Mexico Attorney General (NMAG) has filed a motion to dismiss the rate case or to toll the suspension period of rates, and the NMPRC Staff has also filed a motion to reject the filing and for SPS to file additional information on the grounds that SPS’ information supporting its 2011 test year is incomplete. SPS has filed a response asserting that SPS’ filing is complete and requesting the NMPRC to deny the NMAG's motion. The NMPRC has not yet acted on the motion. The date for SPS to respond to the Staff's motion has not yet been established.

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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 June 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.

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 does 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)	June 30, 2011		Dec. 31, 2010
Current assets	$	3,594	$	3,794
Property, plant and equipment, net		94,728		97,602
Other noncurrent assets		8,176		8,236
Total assets	$	106,498	$	109,632

Current liabilities	$	10,622	$	11,884
Mortgages and other long-term debt payable		52,715		53,195
Other noncurrent liabilities		8,220		8,333
Total liabilities	$	71,557	$	73,412

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

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

(Millions of Dollars)	June 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		31.1		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 Inc. is alleged to be a PRP that sent hazardous materials and wastes. At June 30, 2011 and Dec. 31, 2010, the liability for the cost of remediating these sites was estimated to be $107.1 million and $104.0 million, respectively, of which $6.0 million and $5.7 million, respectively, was considered to be a current liability.

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 (PRAP). 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.

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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 is performing an ongoing site investigation, and has concluded that materials typically associated with the operation of MGPs are present in soils and groundwater at the site. Information obtained from this ongoing investigation indicates some site remediation may be required. The ultimate scope and costs of such remediation are not determinable at this time, and will not be fully determinable until a remediation action plan is submitted and approved by the WDNR. It is anticipated, however, that remediation costs will not have a material adverse effect on Xcel Energy’s consolidated results of operations, cash flow or financial position.

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) Endangerment Rulemaking — 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. The EPA plans to propose GHG regulations applicable to emissions from existing power plants under the Clean Air Act (CAA). In June 2011, the EPA announced that they have delayed the proposal date to September 2011, but still plan on issuing final rules in May 2012.

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Cross State Air Pollution Rule (CSAPR) — On July 7, 2011, the EPA issued its CSAPR. The rule, previously called the Transport Rule, 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 Transport Rule 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, although interstate trading under the rule will be significantly restricted. Xcel Energy may comply by either reducing emissions, purchasing allowances, or a combination of the two. The CSAPR is a final rule and requires compliance beginning in 2012.

Xcel Energy is still evaluating compliance options. At this time, Xcel Energy believes that the CSAPR will likely require the installation of additional emission controls on some of SPS’ coal-fired electric generating units. Xcel Energy also anticipates that NSP-Minnesota and NSP-Wisconsin will ultimately comply with the rule through execution of their existing resource and emission control plans as well as through allowance purchases and other activities. Because the CSAPR requires compliance in 2012, SPS, NSP-Minnesota and NSP-Wisconsin may 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. Xcel Energy is still evaluating our short-term compliance strategy. Xcel Energy believes the cost of any required capital investment, allowance purchases or redispatch costs 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 U.S. Court of Appeals for the District of Columbia 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. CSAPR replaces the CAIR, and will be applicable to our plants 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. These capital investments should assist SPS in complying with the CSAPR once it becomes effective in 2012. At June 30, 2011, the estimated annual CAIR NOx allowance cost for SPS was $0.3 million. At June 30, 2011, the estimated annual CAIR NOx allowance cost for NSP-Wisconsin was $0.1 million. The CSAPR will establish a new emissions market for SO2 and NOx, and Xcel Energy does not yet have enough information to estimate the cost of future CSAPR allowance purchases. Xcel Energy believes the cost of any required capital investment or allowance purchases will be recoverable from customers.

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 intends to issue the final rule by November 2011. Xcel Energy anticipates that the EPA will require affected facilities to demonstrate compliance within three to four years.

Colorado Mercury Regulation — Colorado’s mercury regulations require mercury emission controls capable of achieving 80 percent capture to be installed at the Pawnee Generating Station by 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.

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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.

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 June 30, 2011, the estimated annual testing and study cost is $0.5 million. NSP-Minnesota projects installation costs of $12.0 million for the two 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 only one Xcel Energy plant in Wisconsin.

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 United States (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 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.

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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.

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 (BTA) 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 is evaluating the proposed rule, including possible additional capital and operating expenses, and plans to offer comments to the EPA. 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 Station in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid to late 1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the CAA and NSR process. PSCo also believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position.

Cunningham 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, 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 Sherburne County 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.

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 adverse 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 in 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. On June 20, 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.

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. 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 one 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. In February 2010, the Colorado Supreme Court agreed to review the Court of Appeals’ decision as to the punitive damages issue but will not review the Court of Appeals’ decision as it relates to PSCo. Oral arguments were presented in December 2010. In June 2011, the Colorado Supreme Court affirmed the decision of the Court of Appeals.

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

In March 2008, OSHA proposed penalties totaling $189,900 for 22 serious violations and three willful violations arising out of the accident. In April 2008, Xcel Energy notified OSHA of its decision to contest all of the proposed citations. Pursuant to a court order this proceeding had been stayed until July 1, 2011. The stay has now been lifted, and the matter is expected to proceed.

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Three lawsuits were filed (two in Colorado state court and one in California state court) on behalf of the five deceased workers and by seven employees of RPI allegedly injured in the accident. PSCo and Xcel Energy Inc. were among the defendants named in each lawsuit. Settlements were subsequently reached in all three lawsuits by Xcel Energy Inc. and PSCo. These confidential settlements did not have a material adverse effect upon Xcel Energy’s consolidated results of operations, cash flows or financial position.

In August 2009, the U.S. Government charged Xcel Energy Inc. and PSCo with five misdemeanor counts in federal court in Colorado for violation of an OSHA regulation related to the accident at Cabin Creek in October 2007. RPI Coatings, the contractor performing the work at the plant, and two individuals employed by RPI were also indicted. In September 2009, both Xcel Energy Inc. and PSCo entered a not-guilty plea. On June 28, 2011, a jury returned a not-guilty verdict on all accounts in favor of Xcel Energy Inc. and PSCo.

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

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

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

Trial commenced in October 2010 and addressed only those issues raised in the first complaint and did not include Shaw’s claim asserted in the second lawsuit related to the letter of credit. In November 2010, a jury returned a verdict 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 on April 5, 2011. If the jury verdict remains unchanged it is not expected to have a material adverse 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. Arguments related to this motion are expected to be presented to the court on Sept. 16, 2011. No accrual has been recorded for this matter.

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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 (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 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.

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.

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 June 30, 2011			Twelve Months Ended Dec. 31, 2010
Borrowing limit	$	2,450		$	2,177
Amount outstanding at period end		656			466
Average amount outstanding		548			263
Maximum amount outstanding		692			653
Weighted average interest rate, computed on a daily basis		0.36	%		0.36	%
Weighted average interest rate at end of period		0.35			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 of 2011, NSP-Minnesota, NSP-Wisconsin, PSCo, SPS and Xcel Energy Inc. executed new 4-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.

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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 June 30, 2011 and Dec. 31, 2010 as evidenced by the table below:

	Debt-to-Total Capitalization Ratio
	June 30, 2011			Dec. 31, 2010
NSP-Minnesota		48	%		49	%
PSCo		44			46
SPS		50			50
Xcel Energy		55			55
NSP-Wisconsin		49			N/A

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.

Each credit facility has a cross-default provision that provides Xcel Energy will be in default on its borrowings under the facility if it or any of its subsidiaries, comprising 15 percent or more of the consolidated assets, defaults on any indebtedness in an aggregate principal amount exceeding $75 million.

The interest rates under these lines of credit are based on the Eurodollar rate, plus a borrowing margin based on the applicable credit ratings of 100 to 200 basis points per year.

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.

At June 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	$	336.1	$	463.9
PSCo		700.0		153.6		546.4
NSP-Minnesota		500.0		12.1		487.9
SPS		300.0		131.0		169.0
NSP-Wisconsin		150.0		35.0		115.0
Total	$	2,450.0	$	667.8	$	1,782.2

(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 facility outstanding at June 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 June 30, 2011 and Dec. 31, 2010, there were $11.9 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 facility were outstanding at June 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.

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.

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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.

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 a 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.

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.

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Unrealized gains for the decommissioning fund were $100.6 million and $82.5 million at June 30, 2011 and Dec. 31, 2010, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $56.0 million and $65.2 million at June 30, 2011 and Dec. 31, 2010, respectively.

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 June 30, 2011 and Dec. 31, 2010:

	June 30, 2011
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	64,873	$	62,384	$	2,489	$	-	$	64,873
Commingled funds		220,000		-		223,922		-		223,922
International equity funds		54,563		-		63,736		-		63,736
Debt securities:
Government securities		241,914		-		244,286		-		244,286
U.S. corporate bonds		189,055		-		197,611		-		197,611
Foreign securities		19,542		-		20,626		-		20,626
Municipal bonds		32,392		-		33,474		-		33,474
Asset-backed securities		20,198		-		-		21,004		21,004
Mortgage-backed securities		58,680		-		-		62,271		62,271
Equity securities:
Common stock		442,416		456,426		-		-		456,426
Total	$	1,343,633	$	518,810	$	786,144	$	83,275	$	1,388,229

(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $96.7 million of equity investments in unconsolidated subsidiaries and $32.2 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.

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

	Three Months Ended June 30,
	2011						2010
(Thousands of Dollars)	Mortgage- Backed Securities			Asset- Backed Securities			Mortgage- Backed Securities			Asset- Backed Securities
Balance at April 1	$	98,367		$	26,020		$	109,044		$	44,125
Purchases		52,952			-			-			2,538
Settlements		(88,584	)		(5,206	)		(45,329	)		(6,757	)
(Losses) gains recorded as regulatory assets and liabilities		(464	)		190			1,344			161
Balance at June 30	$	62,271		$	21,004		$	65,059		$	40,067

	Six Months Ended June 30,
	2011						2010
(Thousands of Dollars)	Mortgage- Backed Securities			Asset- Backed Securities			Mortgage- Backed Securities			Asset- Backed Securities
Balance at Jan. 1	$	72,589		$	33,174		$	81,189		$	11,918
Purchases		99,065			756			46,477			36,042
Settlements		(108,457	)		(13,116	)		(66,175	)		(8,109	)
(Losses) gains recorded as regulatory assets and liabilities		(926	)		190			3,568			216
Balance at June 30	$	62,271		$	21,004		$	65,059		$	40,067

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class at June 30, 2011:

	Final Contractual Maturity
	Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years
(Thousands of Dollars)	Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Government securities	$	8,540	$	140,767	$	84,652	$	10,327	$	244,286
U.S. corporate bonds		349		50,672		127,922		18,668		197,611
Foreign securities		-		14,061		6,565		-		20,626