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 March 31, 2011
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-3034

Xcel Energy Inc.

(Exact name of registrant as specified in its charter)

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

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

(612) 330-5500

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. xYes oNo

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). £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 April 19, 2011
Common Stock, $2.50 par value		484,176,449 shares

TABLE OF CONTENTS

PART I		FINANCIAL INFORMATION	2
	Item 1 —	Financial Statements (unaudited)	2
		CONSOLIDATED STATEMENTS OF INCOME	2
		CONSOLIDATED STATEMENTS OF CASH FLOWS	3
		CONSOLIDATED BALANCE SHEETS	4
		CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME	5
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	6
	Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
	Item 3 —	Quantitative and Qualitative Disclosures about Market Risk	48
	Item 4 —	Controls and Procedures	48
PART II		OTHER INFORMATION	49
	Item 1 —	Legal Proceedings	49
	Item 1A —	Risk Factors	49
	Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	50
	Item 6 —	Exhibits	51
SIGNATURES			52
		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).

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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 March 31,
	2011			2010
Operating revenues
Electric	$	2,029,972		$	1,995,592
Natural gas		765,349			790,150
Other		21,219			21,720
Total operating revenues		2,816,540			2,807,462

Operating expenses
Electric fuel and purchased power		931,828			988,478
Cost of natural gas sold and transported		543,376			581,113
Cost of sales — other		8,055			7,692
Other operating and maintenance expenses		510,027			480,973
Conservation and demand side management program expenses		75,298			58,039
Depreciation and amortization		224,723			206,126
Taxes (other than income taxes)		96,570			81,376
Total operating expenses		2,389,877			2,403,797

Operating income		426,663			403,665

Other income, net		4,766			975
Equity earnings of unconsolidated subsidiaries		7,713			7,401
Allowance for funds used during construction — equity		13,244			13,290

Interest charges and financing costs
Interest charges — includes other financing costs of $5,260 and $5,011, respectively		144,354			143,830
Allowance for funds used during construction — debt		(7,436	)		(7,737	)
Total interest charges and financing costs		136,918			136,093

Income from continuing operations before income taxes		315,468			289,238
Income taxes		112,001			121,898
Income from continuing operations		203,467			167,340
Income (loss) from discontinued operations, net of tax		102			(222	)
Net income		203,569			167,118
Dividend requirements on preferred stock		1,060			1,060
Earnings available to common shareholders	$	202,509		$	166,058

Weighted average common shares outstanding:
Basic		483,641			458,918
Diluted		484,301			459,697

Earnings per average common share:
Basic	$	0.42		$	0.36
Diluted		0.42			0.36

Cash dividends declared per common share	$	0.25		$	0.25

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)

	Three Months Ended March 31,
		2011			2010
Operating activities
Net income		$	203,569		$	167,118
Remove (income) loss from discontinued operations			(102	)		222
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization			229,217			210,481
Conservation and demand side management program amortization			3,024			7,757
Nuclear fuel amortization			25,551			25,980
Deferred income taxes			114,852			94,551
Amortization of investment tax credits			(1,580	)		(1,594	)
Allowance for equity funds used during construction			(13,244	)		(13,290	)
Equity earnings of unconsolidated subsidiaries			(7,713	)		(7,401	)
Dividends from unconsolidated subsidiaries			8,454			7,855
Share-based compensation expense			9,895			7,129
Net realized and unrealized hedging and derivative transactions			14,495			(14,875	)
Changes in operating assets and liabilities:
Accounts receivable			(46,947	)		(7,179	)
Accrued unbilled revenues			157,996			172,732
Inventories			118,595			113,784
Other current assets			43,551			821
Accounts payable			(72,424	)		(199,384	)
Net regulatory assets and liabilities			17,853			26,029
Other current liabilities			5,491			(24,731	)
Pension and other employee benefit obligations			(134,004	)		(2,233	)
Change in other noncurrent assets			10,520			(3,610	)
Change in other noncurrent liabilities			(27,606	)		(8,585	)
Net cash provided by operating activities			659,443			551,577

Investing activities
Utility capital/construction expenditures			(540,339	)		(481,242	)
Merricourt deposit			(90,833	)		-
Allowance for equity funds used during construction			13,244			13,290
Purchase of investments in external decommissioning fund			(699,156	)		(910,889	)
Proceeds from the sale of investments in external decommissioning fund			699,156			916,541
Investment in WYCO Development LLC			(901	)		(1,237	)
Change in restricted cash			26			(168	)
Other investments			(5,545	)		3,593
Net cash used in investing activities			(624,348	)		(460,112	)

Financing activities
Proceeds from short-term borrowings, net			65,100			7,000
Repayment of long-term debt, including reacquisition premiums			(551	)		(25,355	)
Proceeds from issuance of common stock			1,878			2,589
Dividends paid			(115,621	)		(105,965	)
Net cash used in financing activities			(49,194	)		(121,731	)

Net decrease in cash and cash equivalents			(14,099	)		(30,266	)
Cash and cash equivalents at beginning of period			108,437			115,648
Cash and cash equivalents at end of period		$	94,338		$	85,382
Supplemental disclosure of cash flow information:
Cash paid for interest, net of amounts capitalized		$	(150,473	)	$	(132,578	)
Cash received (paid) for income taxes, net			59,051			(393	)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable		$	116,145		$	27,396
Supplemental disclosure of non-cash financing transactions:
Issuance of common stock for reinvested dividends and 401(k) plans		$	20,419		$	17,010

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands of dollars)

	March 31, 2011			Dec. 31, 2010
Assets
Current assets
Cash and cash equivalents	$	94,338		$	108,437
Accounts receivable, net		765,421			718,474
Accrued unbilled revenues		550,695			708,691
Inventories		442,205			560,800
Regulatory assets		319,486			388,541
Derivative instruments		55,932			54,079
Merricourt deposit		101,261			-
Prepayments and other		184,791			193,621
Total current assets		2,514,129			2,732,643

Property, plant and equipment, net		20,908,333			20,663,082

Other assets
Nuclear decommissioning fund and other investments		1,511,278			1,476,435
Regulatory assets		2,186,967			2,151,460
Derivative instruments		177,469			184,026
Other		168,473			180,044
Total other assets		4,044,187			3,991,965
Total assets	$	27,466,649		$	27,387,690

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	54,761		$	55,415
Short-term debt		531,500			466,400
Accounts payable		848,568			979,750
Regulatory liabilities		176,511			156,038
Taxes accrued		312,669			254,320
Accrued interest		158,230			163,907
Dividends payable		123,310			122,847
Derivative instruments		30,799			61,745
Other		248,408			276,111
Total current liabilities		2,484,756			2,536,533

Deferred credits and other liabilities
Deferred income taxes		3,567,061			3,390,027
Deferred investment tax credits		91,357			92,937
Regulatory liabilities		1,191,463			1,179,765
Asset retirement obligations		985,466			969,310
Derivative instruments		279,464			285,986
Customer advances		265,213			269,087
Pension and employee benefit obligations		824,500			962,767
Other		226,783			249,635
Total deferred credits and other liabilities		7,431,307			7,399,514

Commitments and contingent liabilities
Capitalization
Long-term debt		9,264,123			9,263,144
Preferred stockholders' equity		104,980			104,980
Common stock – $2.50 par value per share		1,210,411			1,205,834
Additional paid in capital		5,241,533			5,229,075
Retained earnings		1,781,386			1,701,703
Accumulated other comprehensive loss		(51,847	)		(53,093	)
Total common stockholders' equity		8,181,483			8,083,519
Total liabilities and equity	$	27,466,649		$	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									Accumulated			Total
					Additional					Other			Common
					Paid In		Retained			Comprehensive			Stockholders'
	Shares		Par Value		Capital		Earnings			Income (Loss)			Equity
Three Months Ended March 31, 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								167,118						167,118
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $295											419			419
Net derivative instrument fair value changes, net of tax of $460											652			652
Unrealized gain - marketable securities, net of tax of $8											11			11
Comprehensive income for the period														168,200
Dividends declared:
Cumulative preferred stock								(1,060	)					(1,060	)
Common stock								(112,951	)					(112,951	)
Issuances of common stock		1,706		4,265		8,379								12,644
Share-based compensation						5,793								5,793
Balance at March 31, 2010		459,215	$	1,148,038	$	4,784,152	$	1,472,308		$	(48,627	)	$	7,355,871

Balance at Dec. 31, 2010		482,334	$	1,205,834	$	5,229,075	$	1,701,703		$	(53,093	)	$	8,083,519
Net income								203,569						203,569
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $551											794			794
Net derivative instrument fair value changes, net of tax of $292											402			402
Unrealized gain - marketable securities, net of tax of $34											50			50
Comprehensive income for the period														204,815
Dividends declared:
Cumulative preferred stock								(1,060	)					(1,060	)
Common stock								(122,826	)					(122,826	)
Issuances of common stock		1,831		4,577		1,652								6,229
Share-based compensation						10,806								10,806
Balance at March 31, 2011		484,165	$	1,210,411	$	5,241,533	$	1,781,386		$	(51,847	)	$	8,181,483

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 March 31, 2011 and Dec. 31, 2010; the results of its operations and changes in stockholders’ equity for the three months ended March 31, 2011 and 2010; and its cash flows for the three months ended March 31, 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 March 31, 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 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 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

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

Reclassifications — Certain prior year amounts have been reclassified to conform to the current year presentation, including amounts related to discontinued operations and deferred income taxes in the consolidated statements of cash flows.

2.	Accounting Pronouncements

Recently issued accounting pronouncements that have been adopted in the current period did not materially impact the consolidated financial statements, and no material impact is expected from accounting pronouncements issued and pending implementation.

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3.	Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2011				Dec. 31, 2010
Accounts receivable, net
Accounts receivable		$	818,217		$	773,037
Less allowance for bad debts			(52,796	)		(54,563	)
		$	765,421		$	718,474
Inventories
Materials and supplies		$	201,475		$	196,081
Fuel			159,847			188,566
Natural gas			80,883			176,153
		$	442,205		$	560,800
Property, plant and equipment, net
Electric plant		$	25,151,881		$	24,993,582
Natural gas plant			3,484,648			3,463,343
Common and other property			1,562,111			1,555,287
Plant to be retired (a)			220,939			236,606
Construction work in progress			1,385,016			1,186,433
Total property, plant and equipment			31,804,595			31,435,251
Less accumulated depreciation			(11,223,241	)		(11,068,820	)
Nuclear fuel			1,893,576			1,837,697
Less accumulated amortization			(1,566,597	)		(1,541,046	)
		$	20,908,333		$	20,663,082

(a)

In 2009, in accordance with the Colorado Public Utility 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’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 March 31, 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 March 31, 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 March 31, 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)	March 31, 2011			Dec. 31, 2010
Unrecognized tax benefit - Permanent tax positions		$	6.4	$	5.9
Unrecognized tax benefit - Temporary tax positions			34.3		34.6
Unrecognized tax benefit balance		$	40.7	$	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 carryfowards are as follows:

(Millions of Dollars)		March 31, 2011				Dec. 31, 2010
NOL and tax credit carryforwards		$	(38.2	)		$	(38.0	)

The increase in the unrecognized tax benefit balance of $0.2 million from Dec. 31, 2010 to March 31, 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 related to continuing operations 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 partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits is as follows:

(Millions of Dollars)	2011			2010
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(0.3	)	$	(0.2	)
Interest expense related to unrecognized tax benefits - continuing operations		(0.1	)		(0.1	)
Interest income related to unrecognized tax benefits - discontinued operations		0.1			0.1
Payable for interest related to unrecognized tax benefits at March 31	$	(0.3	)	$	(0.2	)

No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 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’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)

Base Rate

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. In January 2011, NSP-Minnesota revised its requested 2011 rate increase to $148.3 million as the result of the sale of certain transmission assets.

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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 remain in effect until the MPUC makes its final decision on the case. An MPUC decision is anticipated in the fourth quarter of 2011.

On April 5, 2011, intervening parties filed direct testimony proposing modifications to NSP-Minnesota’s rate request. The Minnesota Office of Energy Security (OES) recommended a 2011 increase of approximately $56.9 million, based on a recommended ROE of 10.53 percent and an equity ratio of 52.56 percent. The OES recommendation reflected several adjustments, including a $21.5 million decrease in NSP-Minnesota’s proposed 2011 income tax expense and decreases of approximately $12.4 million related to employee compensation, health and pension benefits. The OES also proposed several other reductions totaling approximately $23.5 million, including rent expense, certain nuclear outage costs, transmission increases and disallowance of the revenue requirement related to a portion of NSP-Minnesota’s investment in the Nobles Wind Project ($1.9 million). Finally, the OES recommended an additional increase for 2012 of approximately $34 million to address certain known and measurable cost increases in 2012 associated with our nuclear operations.

Other intervenors included the Minnesota Office of the Attorney General (OAG), the Minnesota Chamber of Commerce, the Large Industrial Customer Group (XLI) and the Commercial Group. The OAG recommended changes to NSP-Minnesota’s proposed deferral and amortization treatment of nuclear outage expenses and NSP-Minnesota’s proposed ratemaking treatment of capitalized retiree medical expenses. The XLI recommended changes to NSP-Minnesota’s proposed ROE and capital structure, as well as a reduction in NSP-Minnesota’s recommended depreciation expense.

The following procedural schedule has been established for the remainder of the case:

●

Rebuttal testimony due May 4, 2011;

●

Surrebuttal testimony due May 26, 2011;

●

Evidentiary hearings June 1-8, 2011;

●

Initial brief due July 29, 2011;

●

Reply brief and findings due Aug. 19, 2011;

●

Administrative law judge (ALJ) report due Sept. 19, 2011; and

●

MPUC order Nov. 28, 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 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 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 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 March 2011, the MPUC approved recovery of the costs requested but denied reallocation of $0.3 million of RDF related costs to Minnesota customers that the North Dakota and South Dakota jurisdictions do not allow in rates. NSP-Minnesota has petitioned for reconsideration of the reallocation issue.

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Annual Automatic Adjustment Report for 2008/2009 — In September 2009, NSP-Minnesota filed its annual electric and natural gas automatic adjustment reports for July 1, 2008 through June 30, 2009. During that time period, $803.6 million in fuel and purchased energy costs were recovered from Minnesota electric customers through the fuel clause adjustment. In addition, approximately $499.4 million of purchased natural gas and transportation costs were recovered from Minnesota natural gas customers through the purchased gas adjustment. The MPUC approved the 2008/2009 annual automatic adjustment report in March 2011.

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.

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 fourth quarter of 2011.

The schedule is as follows:

●

Intervenor direct testimony due June 23, 2011;

●

Rebuttal testimony due July 25, 2011;

●

Evidentiary hearings Aug. 9-12, 2011;

●

Initial briefs due Sept. 16, 2011;

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Reply brief and findings due Sept. 30, 2011; and

●

NDPSC order Nov. 16, 2011.

NSP-Wisconsin

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

Base Rate

NSP-Wisconsin 2010 Electric Fuel Cost Recovery — NSP-Wisconsin over-recovered fuel and purchased power costs by approximately $4.6 million (2.6 percent) in 2010. The total refund obligation under the Wisconsin fuel rules, including interest, is $3.1 million. NSP-Wisconsin refunded the over-recovery to customers in the first quarter of 2011.

PSCo

Pending and Recently Concluded Regulatory Proceedings — CPUC

Base Rate

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, effective in the summer of 2011. In March 2011, PSCo revised its requested rate increase to $25.6 million due to corrections and updates.

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.

On April 11, 2011, intervenors filed answer testimony. The CPUC Staff recommended a rate decrease of $20.1 million, based on the use of a historic test year (HTY), an ROE of 9.375 percent and an equity ratio of 51.82 percent. The CPUC Staff also recommended certain adjustments related to pipeline integrity costs, rate base items and pension and benefits expenses.

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The Colorado Office of Consumer Counsel (OCC) recommended a rate decrease of $1 million, based on an ROE of 9.0 percent, an equity ratio of 57.20 percent and by reducing cash working capital to reflect adjustments to interest on long-term debt. The OCC also recommended adjustments to certain O&M expenses, use of a HTY and recommended that gas stored underground remain in base rates rather than move to a rider. The impact of including gas inventory in base rates would reduce PSCo’s fuel recovery by an additional $9 million.

A final decision is expected in the summer of 2011. The following procedural schedule has been established:

●

PSCo rebuttal testimony and staff and intervenor cross answer testimony is due on May 6, 2011;

●

Hearings are scheduled for late May 2011.

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

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 total PSCo wholesale production 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.

SPS

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

Base Rate

SPS Texas Retail Base Rate Case — In May 2010, SPS filed an electric rate case in Texas seeking an annual base rate increase of approximately $71.5 million inclusive of franchise fees. On a net basis, the request seeks to increase customer bills by approximately $53.4 million, or 7 percent. In November of 2010, SPS reduced its request to approximately $63.7 million and the net request $47.6 million.

During the first quarter of 2011, SPS and various parties entered into a settlement agreement. In March 2011, the PUCT approved the settlement. As a result, effective Feb. 16, 2011, base rates increased by $39.4 million, of which $16.9 million is associated with the transfer of two riders, the Transmission Cost Recovery Factor (TCRF) and Power Cost Recovery Factor into base rates and a $22.5 million traditional base rate increase. In addition, SPS is allowed to defer up to $2.3 million of pension and benefit costs and $1.6 million of renewable energy credits that had been included in SPS’ base rate request.

Effective Jan. 1, 2012, the settlement provides for SPS to increase base rates by $13.1 million and allows SPS to seek an energy efficiency cost recovery factor rider for $2.9 million that if approved would result in an effective rate increase of $16 million. SPS plans to make its filing for the rider by May 1, 2011 pursuant to a recent PUCT order. In addition, SPS is allowed to track and defer up to $4.3 million of pension and benefit costs above the test year levels as well as $1.6 million of renewable energy credits, as described above.

SPS agreed not to file another rate case before Sept. 15, 2012. In addition, SPS cannot file a TCRF until 2013, and if SPS files a TCRF application before the effective date of rates in its next rate case, it must reduce the calculated TCRF revenue requirement by $12.2 million.

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

SPS New Mexico Electric Rate Case — In February 2011, SPS filed an electric rate case in New Mexico with the NMPRC seeking an annual base rate increase of 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 on the grounds that SPS’ information supporting its 2011 test year is incomplete. SPS has filed a response explaining that SPS’ filing is complete and asking the NMPRC to deny the NMAG’s motion. The NMPRC has not yet acted on the motion.

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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’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

Wind Generation — On April 1, 2011, NSP-Minnesota terminated its agreement with enXco Development Corporation for the development of the 150 megawatt (MW) Merricourt Wind Project (Project) in southeastern North Dakota because the closing on the Project did not occur on or before March 31, 2011, and certain conditions required for closing were not satisfied. These conditions included a failure to resolve concerns about potential adverse consequences the Project could have on two endangered species - the whooping crane and piping plover - and a failure to obtain a Certificate of Site Compatibility. The Project was projected to cost approximately $400 million and was expected to reach commercial operation in 2011. As a result, NSP-Minnesota recorded a $101 million deposit, which was subsequently collected in April 2011.

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 and are required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which the 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 4,005 MW and 4,101 MW of capacity under long-term purchased power agreements as of March 31, 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 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 has determined that Eloigne and NSP-Wisconsin have the power to direct the activities that most significantly impact these entities’ economic performance, and therefore Xcel Energy consolidates these limited partnerships in its consolidated financial statements.

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)	March 31, 2011		Dec. 31, 2010
Current assets	$	4,030	$	3,794
Property, plant and equipment, net		96,892		97,602
Other noncurrent assets		8,478		8,236
Total assets	$	109,400	$	109,632

Current liabilities	$	11,781	$	11,884
Mortgages and other long-term debt payable		53,389		53,195
Other noncurrent liabilities		8,392		8,333
Total liabilities	$	73,562	$	73,412

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

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

(Millions of Dollars)	March 31, 2011		Dec. 31, 2010
Guarantees issued and outstanding	$	155.7	$	155.7
Known exposure under these guarantees		18.0		18.0
Bonds with indemnity protection		32.4		32.5

Environmental Contingencies

Xcel Energy and its subsidiaries have been, or are currently, involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, the subsidiary involved believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, the subsidiary involved is pursuing, or intends to pursue, recovery from other potentially responsible parties (PRPs) and through the rate regulatory process. New and changing federal and state environmental mandates can also create added financial liabilities for Xcel Energy and its subsidiaries, which are normally recovered through the rate regulatory process. To the extent any costs are not recovered through the options listed above, Xcel Energy would be required to recognize an expense.

Site Remediation — 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 subsidiaries, predecessors, or other entities; and third-party sites, such as landfills, for which Xcel Energy is alleged to be a PRP that sent hazardous materials and wastes. At March 31, 2011 and Dec. 31, 2010, the liability for the cost of remediating these sites was estimated to be $104.1 million and $104.0 million, respectively, of which $5.4 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 work at the site. The special notice letters request that those PRPs participate in negotiations with the EPA regarding how the PRPs intend to conduct or pay for the cleanup.

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 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.

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NSP-Wisconsin has deferred, as a regulatory asset, the costs accrued for the Ashland site based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site and has authorized recovery of similar remediation costs for other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin biennial retail rate case process.

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.

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 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. The EPA has promulgated permit requirements for GHGs for power plants. These regulations became applicable in 2011. In December 2010, the EPA announced a settlement with several states and environmental groups to begin preparing regulations of emissions from both new and existing steam electric generating units, such as coal-fired power plants, under the Clean Air Act (CAA). The EPA plans to propose these regulations in July 2011 and finalize them in the first half of 2012.

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

In July 2010, the EPA issued the proposed Clean Air Transport Rule (CATR), which would replace CAIR by requiring SO2 and NOx reductions in 31 states and the District of Columbia. The EPA is proposing to reduce these emissions through federal implementation plans for each affected state. The EPA’s preferred approach would set emission limits for each state and allow limited interstate emissions trading. As proposed, CATR will impact Minnesota and Wisconsin for annual SO2 and NOx emissions, and Texas in the form of ozone season NOx emission allowances. Xcel Energy is analyzing the proposed rule to determine whether emission reductions are needed from facilities in these affected states. The EPA is expected to issue the final CATR in summer 2011. Until CATR becomes final, Xcel Energy will continue activities to support CAIR compliance.

CAIR – SPS

Under CAIR’s cap and trade structure, SPS can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. The remaining scheduled capital investments for NOx controls in the SPS region are estimated at $16.4 million. At March 31, 2011, the estimated annual NOx allowance cost for SPS was $0.3 million. Beginning, in 2013, for phase 1, annual purchases of SO2 allowances are estimated to be up to $4.5 million each year. If CATR is implemented as proposed then no SO2 allowances would be purchased since CATR replaces CAIR. Xcel Energy believes the cost of any required capital investment or allowance purchases will be recoverable from customers.

CAIR – NSP-Wisconsin and NSP-Minnesota

At March 31, 2011, the estimated annual NOx allowance cost for NSP-Wisconsin was $0.1 million. Xcel Energy believes the cost of any required capital investment or allowance purchases will be recoverable from customers. In 2009, the EPA published a rule staying the effectiveness of CAIR in Minnesota effective in December 2009. Cost estimates are therefore not included at this time for NSP-Minnesota.

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.

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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. Xcel Energy is evaluating the proposed rule and plans to offer comments to the EPA. 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.

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 March 31, 2011, the estimated annual testing and study cost is $0.9 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. Xcel Energy is evaluating the final rules for compliance options and for possible comments.

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. 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. The Colorado Air Pollution Control Division (CAPCD) has indicated that it expects to submit a Regional Haze BART/Reasonable Further Progress State Implementation Plan (SIP) to the EPA in 2011. In January 2011, the Colorado Air Quality Commission approved a revised Regional Haze BART/Reasonable Further Progress SIP incorporating the Colorado CACJA emission reduction plan. In accordance with Colorado law, the SIP is now before the Colorado general assembly for review prior to submission to the EPA. PSCo anticipates that for those plants included in the Colorado CACJA emission reduction plan, the plan 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.

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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.

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

The MPCA determined that this certification does not alter the proposed SIP. The SIP proposes BART controls for the Sherco generating facilities that are designed to improve visibility in the national parks, but does not require selective catalytic reduction (SCR) on Units 1 and 2. The MPCA concluded that the minor visibility benefits derived from SCR do not outweigh the substantial costs. In December 2009, the MPCA Citizens Board approved the SIP, which has been submitted to the EPA for approval. Until the EPA takes final action on the SIP, the total cost of compliance cannot be estimated with a reasonable degree of certainty.

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 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants. In March 2011, the EPA released a pre-publication version of a 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 has begun an internal review of the possible changes and impacts, including possible additional capital and operating expenses. 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. In September 2010, the NMED issued a final compliance order that contained a penalty of $7.6 million. SPS requested an administrative hearing to contest the order. The administrative hearing scheduled for April 2011 has been postponed indefinitely to permit the parties to explore settlement opportunities.

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Legal Contingencies

Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition. 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.

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 is currently on appeal before the United States Supreme Court. Oral arguments were presented to the Supreme Court on April 19, 2011 and a decision is expected in the summer of 2011.

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy and 23 other utilities, oil, gas and coal companies. Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village. Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss 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.

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. It is unknown when the Colorado Supreme Court will render a decision. No accrual has been recorded for this matter.

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 has been stayed until July 1, 2011.

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 were among the defendants named in each lawsuit. Settlements were subsequently reached in all three lawsuits by Xcel Energy 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.

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In August 2009, the U.S. Government announced that Xcel Energy and PSCo have been charged with five misdemeanor counts in federal court in Colorado for violation of an OSHA regulation related to the accident at Cabin Creek in October 2007. RPI Coatings, the contractor performing the work at the plant, and two individuals employed by RPI have also been indicted. In September 2009, both Xcel Energy and PSCo entered a not guilty plea, and both will vigorously defend against these charges. The trial date has been set for May 31, 2011. No accrual has been recorded for this proceeding nor is it expected that this proceeding will have a material adverse effect upon Xcel Energy’s consolidated results of operations, cash flows or financial position.

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 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. PSCo is actively participating in negotiations with Shaw. 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.

7.	Borrowings and Other Financing Instruments

Money Pool — Xcel Energy 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. The holding company may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in the holding company. The money pool investments and borrowings are eliminated upon consolidation.

Commercial Paper — Xcel Energy 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 March 31, 2011			Twelve Months Ended Dec. 31, 2010
Borrowing limit	$	2,450		$	2,177
Amount outstanding at period end		532			466
Average amount outstanding		532			263
Maximum amount outstanding		735			653
Weighted average interest rate, computed on a daily basis		0.37	%		0.36	%
Weighted average interest rate at end of period		0.34			0.40

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Credit Facilities — In order to use their commercial paper programs to fulfill short-term funding needs, Xcel Energy 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 executed new 4-year credit agreements. The total size of the credit facilities is $2.45 billion and each credit facility expires in March 2015. Xcel Energy and its utility subsidiaries have the right to request an extension of the final maturity date for two additional one year periods, subject to majority bank group approval.

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

●

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

●

Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio of each entity be less than or equal to 65 percent. Each entity was in compliance at March 31, 2011 and Dec. 31 2010 as evidenced by the table below:

	Debt-to-Total Capitalization Ratio
	March 31, 2011			Dec. 31, 2010
NSP-Minnesota		48	%		49	%
PSCo		44			46
SPS		49			50
Xcel Energy — Consolidated		54			55
NSP-Wisconsin		49			N/A

If Xcel Energy 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 March 31, 2011, Xcel Energy and its utility subsidiaries had the following committed credit facilities available:

(Millions of Dollars)	Credit Facility			Drawn (a)		Available
Xcel Energy – Holding Company		$	800.0	$	375.6	$	424.4
PSCo			700.0		46.6		653.4
NSP-Minnesota			500.0		13.1		486.9
SPS			300.0		75.0		225.0
NSP-Wisconsin			150.0		31.0		119.0
Total		$	2,450.0	$	541.3	$	1,908.7

(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 and its subsidiaries had no direct advances on the credit facility outstanding at March 31, 2011 and Dec. 31, 2010.

Letters of Credit — Xcel Energy and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At March 31, 2011 and Dec. 31, 2010, there were $9.9 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 March 31, 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.

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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 enhanced disclosures about assets and liabilities measured at fair value. A hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three Levels in the hierarchy are as follows:

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

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

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

Specific valuation methods include the following:

Cash equivalents — Cash equivalents are recorded at cost plus accrued interest to approximate fair value. Changes in the observed trading prices and liquidity of cash equivalents, including money market funds, are also monitored as additional support for determining fair value.

Investments in equity securities — 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.

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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.

Deferred unrealized gains for the decommissioning fund were $102.2 million and $82.5 million at March 31, 2011 and Dec. 31, 2010, respectively, and unrealized losses and amounts recorded as other than temporary impairments were $58.1 million and $65.2 million at March 31, 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 March 31, 2011 and Dec. 31, 2010:

	March 31, 2011
				Fair Value
(Thousands of Dollars)	Cost			Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents		$	51,430	$	41,655	$	9,775	$	-	$	51,430
Commingled funds			182,000		-		188,252		-		188,252
International equity funds			54,469		-		60,016		-		60,016
Debt securities:
Government securities			207,042		-		207,855		-		207,855
U.S. corporate bonds			228,464		-		241,221		-		241,221
Foreign securities			14,393		-		14,946		-		14,946
Municipal bonds			43,087		-		42,742		-		42,742
Asset-backed securities			25,404		-		-		26,020		26,020
Mortgage-backed securities			94,312		-		-		98,367		98,367
Equity securities:
Common stock			436,129		450,028		-		-		450,028
Total		$	1,336,730	$	491,683	$	764,807	$	124,387	$	1,380,877

(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 $33.7 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 table presents the changes in Level 3 nuclear decommissioning fund assets:

	Three Months Ended March 31,
	2011						2010
	Mortgage-			Asset-			Mortgage-			Asset-
	Backed			Backed			Backed			Backed
(Thousands of Dollars)	Securities			Securities			Securities			Securities
Balance at Jan. 1	$	72,589		$	33,174		$	81,189		$	11,918
Purchases		46,113			756			46,477			33,504
Settlements		(19,873	)		(7,910	)		(20,846	)		(1,352	)
(Losses) gains recognized as regulatory assets and liabilities		(462	)		-			2,224			55
Balance at March 31	$	98,367		$	26,020		$	109,044		$	44,125

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class at March 31, 2011:

	Final Contractual Maturity
(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	$	301	$	138,767	$	47,263	$	21,524	$	207,855
U.S. corporate bonds		-		55,525		163,149		22,547		241,221
Foreign securities		-		12,214		2,732		-		14,946
Municipal bonds		-		-		25,103		17,639		42,742
Asset-backed securities		-		15,103		10,917		-		26,020
Mortgage-backed securities		-		-		1,172		97,195		98,367
Debt securities	$	301	$	221,609	$	250,336	$	158,905	$	631,151

Derivative Instruments Fair Value Measurements

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

Interest Rate Derivatives — Xcel Energy and its utility subsidiaries enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At March 31, 2011, accumulated other comprehensive income (OCI) related to interest rate derivatives included $0.7 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

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

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

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At March 31, 2011, Xcel Energy had various vehicle fuel related contracts designated as cash flow hedges extending through December 2014. Xcel Energy’s utility subsidiaries also enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three months ended March 31, 2011 and March 31, 2010.

At March 31, 2011, accumulated OCI related to commodity derivative cash flow hedges included $0.2 million of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

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

The following table details the gross notional amounts of commodity forwards, options, and FTRs at March 31, 2011 and Dec. 31, 2010:

(Amounts in Thousands) (a)(b)	March 31, 2011	Dec. 31, 2010
Megawatt hours (MWh) of electricity	33,118	46,794
MMBtu of natural gas	32,722	75,806
Gallons of vehicle fuel	750	800

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

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

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

	Three Months Ended March 31,
(Thousands of Dollars)	2011			2010
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(8,094	)	$	(6,435	)
After-tax net unrealized gains related to derivatives accounted for as hedges		244			23
After-tax net realized losses on derivative transactions reclassified into earnings		158			629
Accumulated other comprehensive loss related to cash flow hedges at March 31	$	(7,692	)	$	(5,783	)

Xcel Energy had no derivative instruments designated as fair value hedges during the three months ended March 31, 2011 and March 31, 2010. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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The following tables detail the impact of derivative activity during the three months ended March 31, 2011 and 2010, on OCI, regulatory assets and liabilities, and income:

	Three Months Ended March 31, 2011
	Fair Value							Pre-Tax Amounts
	Changes Recognized							Reclassified into Income
	During the Period in:							During the Period from:								Pre-Tax Gains
	Other			Regulatory				Other				Regulatory				Recognized
	Comprehensive			Assets and				Comprehensive				Assets and				During the Period
(Thousands of Dollars)	Income			Liabilities				Income (Losses)				Liabilities				in Income
Derivatives designated as cash flow hedges
Interest rate		$	-		$	-			$	337	(a)		$	-			$	-
Vehicle fuel and other commodity			389			-				(32	)(e)			-				-
Total		$	389		$	-			$	305			$	-			$	-

Other derivative instruments
Trading commodity		$	-		$	-			$	-			$	-			$	5,600	(b)
Electric commodity			-			8,846				-				(8,888	)(c)			-
Natural gas commodity			-			(7,615	)			-				57,387	(d)			-
Total		$	-		$	1,231			$	-			$	48,499			$	5,600

	Three Months Ended March 31, 2010
	Fair Value							Pre-Tax Amounts
	Changes Recognized							Reclassified into Income
	During the Period in:							During the Period from:								Pre-Tax Gains
	Other			Regulatory				Other				Regulatory				Recognized
	Comprehensive			Assets and				Comprehensive				Assets and				During the Period
(Thousands of Dollars)	Income			Liabilities				Income				Liabilities				in Income
Derivatives designated as cash flow hedges
Interest rate		$	-		$	-			$	159	(a)		$	-			$	-
Vehicle fuel and other commodity			43			-				910	(e)			-				-
Total		$	43		$	-			$	1,069			$	-			$	-

Other derivative instruments
Interest rate		$	-		$	-			$	-			$	-			$	5,381	(a)
Electric commodity			-			(17,179	)			-				(2,727	)(c)			-
Natural gas commodity			-			(36,094	)			-				3,955	(d)			-
Other			-			-				-				-				50	(b)
Total		$	-		$	(53,273	)		$	-			$	1,228			$	5,431

(a)	Recorded to interest charges.

(b)	Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c)	Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

(d)	Recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

(e)	Recorded to O&M expenses.

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Credit Related Contingent Features — Contract provisions of the derivative instruments that the utility subsidiaries enter into may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary is unable to maintain its credit ratings. If the credit ratings of PSCo were downgraded below investment grade, contracts underlying $5.0 million and $5.6 million of derivative instruments in a gross liability position at March 31, 2011 and Dec. 31, 2010, respectively, would have required Xcel Energy to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $8.1 million and $9.8 million, respectively. At March 31, 2011 and Dec. 31, 2010, there was no collateral posted on these specific contracts.

Certain of the utility subsidiaries’ derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy’s utility subsidiaries had no collateral posted related to adequate assurance clauses in derivative contracts as of March 31, 2011 and Dec. 31, 2010.

Recurring Fair Value Measurements — The following tables present for each of the hierarchy Levels, Xcel Energy’s derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2011:

	March 31, 2011
	Fair Value
									Fair Value			Counterparty
(Thousands of Dollars)	Level 1		Level 2			Level 3			Total			Netting (b)				Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-		$	239		$	-		$	239		$	-			$	239
Other derivative instruments:
Trading commodity		279			28,838			5			29,122			(10,837	)			18,285
Electric commodity		-			-			2,653			2,653			(302	)			2,351
Natural gas commodity		-			1,572			-			1,572			(1,022	)			550
Total current derivative assets	$	279		$	30,649		$	2,658		$	33,586		$	(12,161	)			21,425
Purchased power agreements (a)																		34,507