Xcel Energy (XEL) 10-Q 2011 Q1 Quarterly report

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).

1

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

2

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

3

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

4

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

5

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.

6

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.

7

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.

8

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.

9

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;

● 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.

10

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.

11

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

12

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.

13

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.

14

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.

15

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.

16

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.

17

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

18

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.

19

8.  Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosuresprovides 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.

20

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.

21

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.

22

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.

23

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.

24

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
Current derivative instruments																	$	55,932
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-		$	406		$	-		$	406		$	-			$	406
Other derivative instruments:
Trading commodity		-			36,015			-			36,015			(5,394	)			30,621
Total noncurrent derivative assets	$	-		$	36,421		$	-		$	36,421		$	(5,394	)			31,027
Purchased power agreements (a)																		146,442
Noncurrent derivative instruments																	$	177,469

25

	March 31, 2011
	Fair Value
							Fair Value			Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total			Netting (b)				Total
Current derivative liabilities
Other derivative instruments:
Trading commodity	$	518	$	20,993	$	23		$	21,534		$	(15,029	)	$	6,505
Electric commodity		-		-		303			303			(303	)		-
Natural gas commodity		-		2,124		-			2,124			(1,022	)		1,102
Total current derivative liabilities	$	518	$	23,117	$	326		$	23,961		$	(16,354	)		7,607
Purchased power agreements (a)															23,192
Current derivative instruments														$	30,799
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	19,120	$	-		$	19,120		$	(5,394	)	$	13,726
Total noncurrent derivative liabilities	$	-	$	19,120	$	-		$	19,120		$	(5,394	)		13,726
Purchased power agreements (a)															265,738
Noncurrent derivative instruments														$	279,464

(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

(b) The accounting guidance for derivatives and hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between Xcel Energy and a counterparty. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

Xcel Energy recognizes transfers between Levels as of the beginning of each period.  There were no transfers of amounts between Levels for the three months ended March 31, 2011.  The following table presents the transfers that occurred from Level 3 to Level 2 for the three months ended March 31, 2010:

(Thousands of Dollars)
Trading commodity derivatives not designated as cash flow hedges:
Current assets	$	6,555
Noncurrent assets		14,125
Current liabilities		(3,339	)
Noncurrent liabilities		(6,800	)
Total	$	10,541

There were no transfers to or from Level 1 for the three months ended March 31, 2010, and the transfer of amounts from Level 3 to Level 2 is due to the passing of time and resulting increased availability of observable inputs to value certain long-term derivative contracts.

26

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 Dec. 31, 2010:

	Dec. 31, 2010
	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	$	-	$	126	$	-		$	126		$	-		$	126
Other derivative instruments:
Trading commodity		487		37,019		-			37,506			(21,352	)		16,154
Electric commodity		-		-		3,619			3,619			(1,226	)		2,393
Natural gas commodity		-		1,595		-			1,595			(1,219	)		376
Total current derivative assets	$	487	$	38,740	$	3,619		$	42,846		$	(23,797	)		19,049
Purchased power agreements (a)															35,030
Current derivative instruments														$	54,079
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	150	$	-		$	150		$	-		$	150
Other derivative instruments:
Trading commodity		-		32,621		-			32,621			(4,595	)		28,026
Natural gas commodity		-		1,246		-			1,246			(269	)		977
Total noncurrent derivative assets	$	-	$	34,017	$	-		$	34,017		$	(4,864	)		29,153
Purchased power agreements (a)															154,873
Noncurrent derivative instruments														$	184,026

27

	Dec. 31, 2010
	Fair Value
							Fair Value			Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total			Netting (b)				Total
Current derivative liabilities
Other derivative instruments:
Trading commodity	$	392	$	30,608	$	-		$	31,000		$	(24,007	)	$	6,993
Electric commodity		-		-		1,227			1,227			(1,227	)		-
Natural gas commodity		20		52,709		-			52,729			(21,169	)		31,560
Total current derivative liabilities	$	412	$	83,317	$	1,227		$	84,956		$	(46,403	)		38,553
Purchased power agreements (a)															23,192
Current derivative instruments														$	61,745
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	18,878	$	-		$	18,878		$	(4,596	)	$	14,282
Natural gas commodity		-		438		-			438			(269	)		169
Total noncurrent derivative liabilities	$	-	$	19,316	$	-		$	19,316		$	(4,865	)		14,451
Purchased power agreements (a)															271,535
Noncurrent derivative instruments														$	285,986

(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

(b) The accounting guidance for derivatives and hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between Xcel Energy and a counterparty. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

The following table presents the changes in Level 3 commodity derivatives for the three months ended March 31, 2011 and 2010:

	Three Months Ended March 31,
(Thousands of Dollars)	2011			2010
Balance at Jan. 1	$	2,392		$	28,042
Purchases		-			(1,408	)
Settlements		(86	)		(24	)
Transfers out of Level 3		-			(10,541	)
Gains recognized in earnings (a)		68			7,457
Gains (losses) recorded as regulatory assets and liabilities		8,846			(16,904	)
Gains reclassified from regulatory assets and liabilities to earnings		(8,888	)		(2,676	)
Balance at March 31	$	2,332		$	3,946

(a) These amounts relate to commodity derivatives held at the end of the period.

Realized and unrealized gains and losses on commodity trading activities are included in electric revenues. Realized and unrealized gains and losses on non-trading derivative instruments are recorded in OCI or deferred as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on the commission approved regulatory recovery mechanisms.

28

Fair Value of Long-Term Debt Recorded at Carrying Amount

The carrying amounts and fair values of Xcel Energy’s long-term debt are as follows:

	March 31, 2011				Dec. 31, 2010
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Long-term debt, including current portion	$	9,318,884	$	10,126,542	$	9,318,559	$	10,224,845

The fair value of Xcel Energy’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.  The fair value estimates presented are based on information available to management as of March 31, 2011 and Dec. 31, 2010.  These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since that date, and current estimates of fair values may differ significantly.

As of March 31, 2011 and Dec. 31, 2010, the carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities are representative of fair value because of the short-term nature of these instruments.

9.  Other Income, Net

Other income (expense), net consisted of the following:

	Three Months Ended March 31,
(Thousands of Dollars)		2011			2010
Interest income		$	4,773		$	2,051
Other nonoperating income			864			584
Insurance policy expense			(871	)		(1,660	)
Other income, net		$	4,766		$	975

10.  Segment Information

The regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo are each separately and regularly reviewed by Xcel Energy’s chief operating decision maker.  Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided.  These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

Given the similarity of the regulated electric and regulated natural gas utility operations of its utility subsidiaries, Xcel Energy has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.

· Xcel Energy’s regulated electric utility segment generates electricity which is transmitted and distributed in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas, and New Mexico.  In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States.  Regulated electric utility also includes commodity trading operations.

· Xcel Energy’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.

· Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category.  Those primarily include steam revenue, appliance repair services, nonutility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits.

Xcel Energy had equity investments in unconsolidated subsidiaries of $96.7 million and $97.6 million as of March 31, 2011 and Dec. 31, 2010, respectively, included in the regulated natural gas segment.

29

Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments because as an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

To report income from continuing operations for regulated electric and regulated natural gas utility segments the majority of costs are directly assigned to each segment.  However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators.  A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended March 31, 2011
Operating revenues from external customers	$	2,029,972	$	765,349	$	21,219		$	-		$	2,816,540
Intersegment revenues		339		799		-			(1,138	)		-
Total revenues	$	2,030,311		766,148		21,219			(1,138	)	$	2,816,540
Income (loss) from continuing operations	$	154,637	$	58,597	$	(9,767	)	$	-		$	203,467

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended March 31, 2010
Operating revenues from external customers	$	1,995,592	$	790,150	$	21,720		$	-		$	2,807,462
Intersegment revenues		1,138		1,703		-			(2,841	)		-
Total revenues	$	1,996,730	$	791,853	$	21,720		$	(2,841	)	$	2,807,462
Income (loss) from continuing operations	$	115,182	$	63,026	$	(10,868	)	$	-		$	167,340

11.  Common Stock and Equivalents

Common Stock Equivalents — Xcel Energy has common stock equivalents consisting of 401(k) equity awards and stock options.  Restricted stock units and performance shares are considered common stock equivalents when all necessary conditions for issuance have been satisfied by the end of the reporting period.

As of March 31, 2011 and 2010, Xcel Energy had approximately 2.5 million and 6.6 million weighted average options outstanding, respectively, that were antidilutive, and therefore, excluded from the earnings per share calculation.  The dilutive impact of common stock equivalents affecting earnings per share was as follows:

	Three Months Ended March 31, 2011							Three Months Ended March 31, 2010
(Amounts in thousands, except per share data)	Income			Shares		Per Share Amount		Income			Shares		Per Share Amount
Net income	$	203,569						$	167,118
Less: Dividend requirements on preferred stock		(1,060	)						(1,060	)
Basic earnings per share:
Earnings available to common shareholders		202,509			483,641	$	0.42		166,058			458,918	$	0.36
Effect of dilutive securities:
401(k) equity awards					660							779
Diluted earnings per share:
Earnings available to common shareholders	$	202,509			484,301	$	0.42	$	166,058			459,697	$	0.36

30

12.  Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended March 31,
		2011			2010			2011			2010
								Postretirement Health
(Thousands of Dollars)	Pension Benefits							Care Benefits
Service cost		$	18,112		$	17,618		$	1,315		$	1,038
Interest cost			39,915			40,652			10,551			10,529
Expected return on plan assets			(55,286	)		(58,124	)		(7,968	)		(7,134	)
Amortization of transition obligation			-			-			3,611			3,611
Amortization of prior service cost (credit)			5,633			5,164			(1,233	)		(1,233	)
Amortization of net loss			18,729			11,024			3,343			2,709
Net periodic benefit cost			27,103			16,334			9,619			9,520
Costs not recognized and additional cost recognized due to the effects of regulation			(7,885	)		(7,326	)		973			973
Net benefit cost recognized for financial reporting		$	19,218		$	9,008		$	10,592		$	10,493

Voluntary contributions of $134 million were made to three of Xcel Energy’s pension plans in January 2011.Based on updated valuation results received in March 2011 for the NCE Non-Bargaining Pension Plan, Xcel Energy plans to make a required contribution of $3.3 million to the NCE Non-Bargaining Pension Plan in mid-2011.

Item 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future.  It should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes to the consolidated financial statements.  Due to the seasonality of Xcel Energy’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where Xcel Energy has a financial interest; customer business conditions; competitive factors, including the extent and timing of the entry of additional competition in the markets served by Xcel Energy and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions by regulatory bodies impacting our nuclear operations, including those affecting costs, operations or the approval of requests pending before the NRC; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee work force factors; the items described under Factors Affecting Results of Continuing Operations; and the other risk factors listed from time to time by Xcel Energy in reports filed with the SEC, including “Risk Factors” in Item 1A of Xcel Energy’s Form 10-K for the year ended Dec. 31, 2010, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended March 31, 2011.

31

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future.  It should be read in conjunction with the accompanying consolidated financial statements and the related notes to consolidated financial statements.

The only common equity securities that are publicly traded are common shares of Xcel Energy. The earnings and earning per share (EPS) of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole. EPS by subsidiary is a financial measure not recognized under GAAP that is calculated by dividing the net income or loss attributable to controlling interest of each subsidiary by the weighted average fully diluted Xcel Energy common shares outstanding for the period. We use this non-GAAP financial measure to evaluate earnings results and to provide details of earnings results. We believe that this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. This non-GAAP financial measure should not be considered as an alternative to our consolidated fully diluted EPS determined in accordance with GAAP as an indicator of operating performance.

Results of Operations

The following table summarizes the diluted earnings per share for Xcel Energy:

	Three Months Ended March 31,
Diluted Earnings (Loss) Per Share		2011			2010
PSCo		$	0.20		$	0.23
NSP-Minnesota			0.19			0.15
NSP-Wisconsin			0.03			0.03
SPS			0.02			0.02
Equity earnings of unconsolidated subsidiaries			0.01			0.01
Regulated utility — continuing operations			0.45			0.44
Holding company and other costs			(0.03	)		(0.02	)
Ongoingdiluted earnings per share			0.42			0.42
COLI settlement, PSRI and Medicare Part D			-			(0.06	)
GAAPdiluted earnings per share		$	0.42		$	0.36

Ongoing earnings exclude adjustments for certain items.  For 2010, these adjustments are related to the corporate owned life insurance (COLI) program, P.S.R. Investments, Inc. (PSRI) and to the Patient Protection and Affordable Care Act — Medicare Part D.

Adjustments to GAAP Earnings

PSRI — During the first quarter of 2010, Xcel Energy recorded a non-recurring tax and interest charge of approximately $10 million, or $0.02 per share, due to an agreement in principle reached with the IRS following the completion of a financial reconciliation of Xcel Energy’s statement of account dating back to tax year 1993, related to the COLI program.

Impact of the Patient Protection and Affordable Care Act — Medicare Part D — During the first quarter of 2010, Xcel Energy recorded non-recurring tax expense of approximately $17 million, or $0.04 per share, of tax benefits previously recognized in income related to Medicare Part D subsidies due to the Patient Protection and Affordable Care Act enacted in March 2010.  Under GAAP, Xcel Energy was required to reverse these previously recorded tax benefits in the period of enactment of the new legislation.

Xcel Energy’s management believes that ongoing earnings provide a meaningful comparison of earnings results and is representative of Xcel Energy’s fundamental core earnings power.  Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, for reporting of results to the Board of Directors, in determining whether performance targets are met for performance-based compensation and when communicating its earnings outlook to analysts and investors.

Earnings Adjusted for Certain Items (Ongoing Earnings)

Xcel Energy — Overall, ongoing earnings were flat for the first quarter of 2011 compared with 2010.

32

PSCo — PSCo earnings decreased by $0.03 per share for the first quarter of 2011.  The decrease is due to seasonal rates, which were implemented in June 2010 and higher O&M expenses, property taxes and depreciation expense.  Seasonal rates are designed to be revenue neutral on an annual basis.  Therefore, the quarterly pattern of revenue collection is different than in the past, as seasonal rates are higher in the summer months and lower throughout the latter part of the year.

NSP-Minnesota — NSP-Minnesota earnings increased by $0.04 per share for the first quarter of 2011.  The increase is primarily due to interim rate increases in Minnesota and North Dakota effective in the current period as well as moderate sales growth and weather, partially offset by higher O&M expenses, property taxes and depreciation expense.

NSP-Wisconsin — NSP-Wisconsin earnings were flat for the first quarter of 2011.  Higher new electric rates, which were effective in January 2011, were offset by higher O&M expenses as well as higher depreciation expense.

SPS — SPS earnings were flat for the first quarter of 2011.  Higher electric margin was offset by higher O&M expenses.

Changes in Diluted Earnings Per Share

The following tables summarize significant components contributing to the changes in the diluted earnings per share compared with prior periods, which are discussed in more detail later.

	Three Months
Diluted Earnings (Loss) Per Share	Ended March 31,
2010 GAAP diluted earnings per share		$	0.36
COLI settlement, PSRI and Medicare Part D			0.06
2010 ongoing diluted earnings per share			0.42
Components of change — 2011 vs. 2010
Higher electric margins			0.12
Higher natural gas margins			0.02
Higher operating and maintenance expenses			(0.04	)
Higher depreciation and amortization			(0.03	)
Higher conservation and DSM expenses (generally offset in revenues)			(0.02	)
Higher taxes (other than income taxes)			(0.02	)
Dilution from DSPP, benefit plans and the 2010 common equity issuance			(0.02	)
Other, net			(0.01	)
2011 GAAP and ongoing diluted earnings per share		$	0.42

The following table provides a reconciliation of ongoing and GAAP earnings and earnings per diluted share:

	Three Months Ended March 31,
Contributions to Income (Millions of Dollars)		2011			2010
GAAP income (loss) by segment
Regulated electric income		$	154.6		$	115.2
Regulated natural gas income			58.6			63.0
Other income (a)			5.0			(4.3	)
Segment income — continuing operations			218.2			173.9
Holding company and other costs (a)			(14.7	)		(6.6	)
Total income — continuing operations			203.5			167.3
Income (loss) from discontinued operations			0.1			(0.2	)
Total GAAP net income		$	203.6		$	167.1

33

	Three Months Ended March 31,
Contributions to Diluted Earnings (Loss) Per Share		2011			2010
GAAP earnings (loss) by segment
Regulated electric		$	0.32		$	0.25
Regulated natural gas			0.12			0.14
Other (a)			0.01			(0.01	)
Segment earnings per share — continuing operations			0.45			0.38
Holding company and other costs(a)			(0.03	)		(0.02	)
Total earnings per share — continuing operations			0.42			0.36
Discontinued operations			-			-
Total GAAP earnings per share — diluted		$	0.42		$	0.36

(a) Not a reportable segment.  Included in all other segment results in Note 10 to the consolidated financial statements.

Statement of Income Analysis

The following discussion summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.

Estimated Impact of Temperature Changes on Regulated Earnings — Unseasonably hot summers or cold winters increase electric and natural gas sales while, conversely, mild weather reduces electric and natural gas sales.  The estimated impact of weather on earnings is based on the number of customers, temperature variances and the amount of natural gas or electricity the average customer historically uses per degree of temperature.  Accordingly, deviations in weather from normal levels can affect Xcel Energy’s financial performance.

Degree-day or Temperature-Humidity Index (THI) data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity.  Heating degree-days (HDD) is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit, and cooling degree-days (CDD) is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit.  Each degree of temperature above 65° Fahrenheit is counted as one cooling degree-day, and each degree of temperature below 65° Fahrenheit is counted as one heating degree-day.  In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD.  HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers.  Industrial customers are less weather sensitive.

Normal weather conditions are defined as either the 20-year or 30-year average of actual historical weather conditions.  The historical period of time used in the calculation of normal weather differs by jurisdiction based on the time period used by the regulator in establishing estimated volumes in the rate setting process.  There was no impact on sales in the first quarter due to THI or CDD.  The percentage increase in normal and actual HDD is provided in the following table:

	Three Months Ended March 31,
	2011 vs.		2010 vs.		2011 vs.
	Normal		Normal		2010
HDD	5.2	%	0.8	%	4.4	%

Weather — The following table summarizes the estimated impact of temperature variations on earnings per share compared with sales under normal weather conditions:

	Three Months Ended March 31,
	2011 vs.			2010 vs.		2011 vs.
		Normal		Normal		2010
Retail electric		$	0.00	$	0.00	$	0.00
Firm natural gas			0.01		0.00		0.01
Total		$	0.01	$	0.00	$	0.01

34

Sales Growth (Decline) — The following table summarizes Xcel Energy’s regulated sales growth (decline) for actual and weather-normalized sales in 2011:

	Three Months Ended March 31,
	Actual		Weather Normalized		Actual Lubbock (a)		Weather Normalized Lubbock (a)
Electric residential	0.1	%	(0.8)	%	0.9	%	0.1	%
Electric commercial and industrial	0.8		0.6		1.7		1.5
Total retail electric sales	0.6		0.2		1.4		1.1
Firm natural gas sales	1.1		(2.1)		1.1		(2.1)

(a) Adjusted for the October 2010 sale of SPS electric distribution assets to the city of Lubbock, Texas.

Electric Revenues and Margin

Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas, coal and uranium used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses these price fluctuations have little impact on electric margin.  The following tables details the electric revenues and margin:

	Three Months Ended March 31,
(Millions of Dollars)		2011			2010
Electric revenues		$	2,030		$	1,996
Electric fuel and purchased power			(932	)		(988	)
Electric margin		$	1,098		$	1,008

The following tables summarize the components of the changes in electric revenues and margin:

Electric Revenues

	Three Months
	Ended March 31,
(Millions of Dollars)	2011 vs. 2010
Fuel and purchased power cost recovery		$	(57	)
Trading			(7	)
Retail rate increases, including seasonal rates (Minnesota interim, Wisconsin, Texas, North Dakota interim and Colorado)			34
Revenue requirements for PSCo gas generation acquisition (a)			34
Transmission revenue			11
Non-fuel riders			8
Conservation and DSM revenue and incentive (partially offset by expenses)			6
Estimated impact of weather			4
Retail sales increase (excluding weather impact)			1
Total increase in electric revenues		$	34

35

Electric Margin

	Three Months
		Ended March 31,
(Millions of Dollars)		2011 vs. 2010
Retail rate increases, including seasonal rates (Minnesota interim, Wisconsin,Texas, North Dakota interim and Colorado)		$	34
Revenue requirements for PSCo gas generation acquisition (a)			34
Non-fuel riders			8
Conservation and DSM revenue and incentive (partially offset by expenses)			6
Estimated impact of weather			4
Retail sales increase (excluding weather impact)			1
Other, net			3
Total increase in electric margin		$	90

(a) The increase in revenue requirements for PSCo generation reflects the acquisition of the Rocky Mountain and Blue Spruce natural gas facilities in 2010.  These revenue requirements are partially offset by increased O&M expense, depreciation expense, property taxes and financing costs.

Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and the cost of natural gas purchases.  However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.  The following tables details natural gas revenues and margin:

	Three Months Ended March 31,
(Millions of Dollars)		2011			2010
Natural gas revenues		$	765		$	790
Cost of natural gas sold and transported			(543	)		(581	)
Natural gas margin		$	222		$	209

The following tables summarize the components of the changes in natural gas revenues and margin:

Natural Gas Revenues

	Three Months
	Ended March 31,
(Millions of Dollars)	2011 vs. 2010
Purchased natural gas adjustment clause recovery		$	(37	)
Retail sales decrease (excluding weather impact)			(3	)
Conservation and DSM revenue and incentive (partially offset by expenses)			10
Estimated impact of weather			5
Other, net			-
Total decrease in natural gas revenues		$	(25	)

Natural Gas Margin

	Three Months
	Ended March 31,
(Millions of Dollars)	2011 vs. 2010
Conservation and DSM revenue and incentive (partially offset by expenses)	$	10
Estimated impact of weather		5
Retail sales decrease (excluding weather impact)		(3	)
Other, net		1
Total increase in natural gas margin	$	13

36

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased by $29.1 million, or 6.0 percent, for the first quarter of 2011 compared with the same period in 2010.  The following table summarizes the changes in other O&M expenses:

	Three Months
	Ended March 31,
(Millions of Dollars)	2011 vs. 2010
Higher labor and contract labor costs	$	9
Higher employee benefit expense		6
Higher plant generation costs		4
Higher nuclear plant operation costs		3
Other, net		7
Total increase in operating and maintenance expenses	$	29

● Higher labor and contract labor costs are primarily due to maintenance on our distribution facilities, particularly in Colorado.

● Higher employee benefit expense is primarily due to higher pension expense.

● Higher plant generation costs are primarily due to the incremental costs associated with new generation placed in service in 2010.

Conservation and DSM Program Expenses — Conservation and DSM program expenses increased by approximately $17.3 million, or 29.7 percent, for the first quarter of 2011 compared with the same period in 2010.  The higher expense is attributable to the continued expansion of programs and regulatory commitments.  Conservation and DSM program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates. Overall, the programs are designed to encourage the operating companies and their retail customers to conserve energy or change energy usage patterns in order to reduce peak demand on the gas or electric system.  This, in turn, reduces the need for additional plant capacity, reduces emissions, serves to achieve other environmental goals as well as reduces energy costs to participating customers.

Depreciation and Amortization — Depreciation and amortization expenses increased by approximately $18.6 million, or 9.0 percent, for the first quarter of 2011 compared with the same period in 2010.  The change in depreciation expense is primarily due to Comanche Unit 3 going into service in the second quarter of 2010, the Nobles Wind Project and the acquisition of two gas generation facilities in December 2010 and normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased by approximately $15.2 million, or 18.7 percent, for the first quarter of 2011 compared with the same period in 2010.  The increase is primarily due to an increase in property taxes in Colorado and Minnesota.

Interest Charges — Interest charges increased by approximately $0.5 million, or 0.4 percent, for the first quarter of 2011 compared with the same period in 2010.  The increase is due to higher long-term debt levels to fund investments in utility operations, partially offset by lower interest rates.

Income Taxes — Income tax expense for continuing operations decreased $9.9 million for the first quarter of 2011, compared with the same period in 2010.  The decrease in income tax expense was primarily due to the 2010 adjustments for a write-off of tax benefit previously recorded for Medicare Part D subsidies and an adjustment related to the corporate owned life insurance (COLI) Tax Court proceedings.  These were partially offset by a reversal of a valuation allowance for certain state tax credit carryovers in 2010 and an increase in pretax income in 2011.  The effective tax rate for continuing operations was 35.5 percent for the first quarter of 2011 compared with 42.1 percent for the same period in 2010.  The higher effective tax rate for 2010 was primarily due to the adjustments referenced above. Without these adjustments, the effective tax rate for continuing operations for the first quarter of 2010 would have been 35.5 percent.

Factors Affecting Results of Operations

Fuel Supply and Costs

See the discussion of fuel supply and costs in Item 7 in Xcel Energy’s Annual Report on Form 10-K filed for the year ended Dec. 31, 2010.

37

Utility Competition — The FERC has continued its efforts to promote competitive wholesale markets through open access transmission and other means.  As a consequence, Xcel Energy’s utility subsidiaries and their wholesale customers can purchase the output from generation resources of competing wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to the utility subsidiaries’ to serve their native load.  NSP-Wisconsin’s two largest wholesale customers, the cities of Medford, Wis. and Rice Lake, Wis., issued notices in December 2010 that power supply contracts with NSP-Wisconsin will be cancelled and power will be purchased from an alternate supplier.  Under the notice provisions in their contracts, Medford will terminate service at the end of 2011 and Rice Lake will terminate service at the end of 2012.  Subsequently, the remaining eight municipal wholesale customers issued notices stating power supply contracts with NSP-Wisconsin will be cancelled at the end of 2012 and power will be purchased from an alternate supplier starting in 2013.  Until the contracts terminate, the municipal wholesale customers will be served under their existing contracts and the formula rate.  In 2010, these ten municipal wholesale customers represented approximately 6 percent of NSP-Wisconsin’s total electric operating revenue.

Public Utility Regulation

NSP-Minnesota

Wind Generation — NSP-Minnesota invested approximately $500 million in wind generation through 2010.  The 201 MW Nobles Wind Project in southwestern Minnesota began commercial operations in 2010.  The portion of the costs for the Nobles Wind Project assigned to Minnesota electric retail customers is currently being collected through the renewable energy standard rider.  NSP-Minnesota had included the costs for the Nobles Wind Project in its current pending rate case in Minnesota and if approved, the costs will be recovered in base rates when final rates are implemented.

On April 1, 2011, NSP-Minnesota terminated its agreement with enXco Development Corporation for the development of the 150 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.

NSP-Minnesota Transmission Certificate of Need (CONs) — In May 2009, the MPUC granted a CON to construct three 345 kilovolt (KV) electric transmission lines as part of the CapX2020 project.  The project to build the three lines includes construction of approximately 700 miles of new facilities at a cost of approximately $1.9 billion.  The portion of the project cost to be constructed by NSP-Minnesota and NSP-Wisconsin is estimated to be approximately $1.0 billion.  The remainder of the costs will be born by other utilities in the upper Midwest.  These cost estimates will be revised after the regulatory process is completed.

NSP-Minnesota and Great River Energy filed four route permit applications with the MPUC in addition to a facility permit application with the South Dakota Public Utility Commission (SDPUC), a certificate of corridor compatibility application with the NDPSC and a Certificate of Public Convenience and Necessity (CPCN) application with the PSCW.  Two filed route permit applications have completed the evidentiary hearing processes, and the MPUC issued route permits for the Monticello, Minn. to St. Cloud, Minn. project and five of the six segments of the Brookings, S.D. to Hampton, Minn. project.  One segment of the Brookings, S.D. to Hampton, Minn. line was referred back to the ALJ to develop more information concerning the appropriate location to cross the Minnesota River.  The MPUC issued a route permit for the last segment of the line in March 2011.  A request from landowners for reconsideration is pending MPUC action.  The other two CapX2020 route applications are expected to be sent to an evidentiary hearing in 2011.

Bemidji to Grand Rapids

In July 2009, the MPUC approved the CON application for a 230 KV CapX2020 transmission line between Bemidji, Minn. and Grand Rapids, Minn.  Route permit hearings were concluded in May 2010, and a route permit was approved by the MPUC in November 2010.  In February 2011, the Leech Lake Band of Ojibwa filed a letter with the MPUC requesting suspension or revocation of the route permit.  MPUC action in response to the request is expected in the second quarter of 2011.  This line is expected to entail construction of approximately 68 miles of new facilities at a cost of $100 million.  Construction related activities began in January 2011 and are expected to be completed in 2012.  The estimated project cost to NSP-Minnesota is approximately $26 million.

Hiawatha Transmission Project

In November 2010, NSP-Minnesota submitted a CON application to the MPUC for two 115 KV lines in Minneapolis, Minn.  Hearings on the CON will be held mid-2011 with an expectation of an MPUC decision of the CON and route permit by the end of 2011.

38

Glencoe to Waconia

In November 2010, NSP-Minnesota submitted a CON to the MPUC for 115 KV transmission line upgrades to the Glencoe, Minn. to Waconia, Minn. 69 KV line.  This was followed by a route permit application filed in December 2010.  Hearings on both applications will be held in mid-2011 with an expectation of an MPUC decision regarding both applications by the end of 2011.

Black Dog Repowering CON — In March 2011, NSP-Minnesota filed a request with Minnesota regulators to approve a CON for a project to retire its last two coal-burning units (Units 3 and 4) at the Black Dog plant in Burnsville, Minn., and replace them with combined-cycle natural gas burning units.  Units 1 and 2 were converted to natural gas combined-cycle operation in 2002.

The proposed Black Dog repowering project would replace the remaining 253 MW of coal-fired generating capacity at the site with about 700 MW of natural gas-fired generation.  The Black Dog proposal requires review and approval by various state agencies, including the MPCA and MPUC. 

If the Black Dog project is approved, site preparation could begin in 2012 and foundation construction could begin in 2013.  The new natural gas powered facility is expected to cost approximately $600 million and is proposed to come on line in 2016.  Recent changes in wholesale and retail load may affect the proposed in-service date.

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant, which has one unit, and the Prairie Island plant, which has two units.  See Note 15 to the Xcel Energy Annual Report on Form 10-K for the year ended Dec. 31, 2010 for further discussion regarding the nuclear generating plants.  Nuclear power plant operation produces gaseous, liquid and solid radioactive wastes.  The discharge and handling of such wastes are controlled by federal regulation.  High-level radioactive wastes primarily include used nuclear fuel.  Low-level radioactive waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.

NRC Regulation — The NRC regulates the nuclear operations of NSP-Minnesota.  Decisions by the NRC can significantly impact Xcel Energy's results of operations.  The recent event at the nuclear plant in Fukushima, Japan could impact the NRC’s deliberations on NSP-Minnesota’s power uprates and life extensions discussed below.  The event in Japan could also result in additional regulation by the NRC.  This additional regulation could require additional capital expenditures or operating expenses.

Nuclear Plant Power Uprates and Life Extension

Monticello Nuclear Extended Power Uprate — In 2008, NSP-Minnesota filed for an extended power uprate of approximately 71 MW for NSP-Minnesota’s Monticello plant.  The MPUC approved the extended power uprate in 2008.  The filing was placed on hold by the NRC staff to address concerns raised by the Advisory Committee for Reactor Safety (ACRS) related to containment pressure associated with pump performance.  The industry submitted a white paper and the NRC staff recommended that the matter be addressed through specific filings to demonstrate any potential risk and mitigation measures.  In a letter to the NRC staff, the ACRS indicated that modifications to the plant should be evaluated and made where practical.  The MPUC provided guidance that allows the MPUC staff to reinitiate its review of NSP-Minnesota’s filing.  NSP-Minnesota is working with the NRC to determine whether an additional supplement to its filing will be necessary to address the issues and expects to complete the license proceeding in late 2011.

Prairie Island Life Extension— In 2008, NSP-Minnesota filed an application with the NRC to renew the operating license of its two nuclear reactors at Prairie Island for an additional 20 years, until 2033 and 2034, respectively.  The NRC staff is proceeding with the items necessary to process Prairie Island’s license renewal application and NSP-Minnesota anticipates receiving a final decision on the Prairie Island license renewal in 2011.

Prairie Island Nuclear Extended Power Uprate — In 2008, NSP-Minnesota filed for an extended power uprate of approximately 164 MW for NSP-Minnesota’s Prairie Island Units 1 and 2.  The MPUC approved the extended power uprate in 2009.  NSP-Minnesota cannot file for NRC approval of the extended power uprate until after the NRC renews the plants’ current operating licenses.  A decision is currently expected in 2011.  The extended power uprates are scheduled to be implemented during the 2014 and 2015 refueling outages.

39

NSP-Wisconsin

NSP-Wisconsin CPCN — An application for a CPCN for the Wisconsin portion of the CapX2020 project was filed with the PSCW in January 2011.  In February 2011, the PSCW determined the application was not complete and requested additional information in order to determine completeness.  A revised CPCN application with the requested information was filed with the PSCW in April 2011.  There have been issues raised by the Wisconsin Department of Transportation regarding placement of one of the routes near the Great River Road and by the Wisconsin Department of Natural Resources regarding a section of a route which passes through the Van Loon Wildlife Area in Wisconsin.  There are route options which could avoid those areas if the PSCW determines those issues warrant such a decision.  No major issues regarding need have been raised and it is expected a decision will be issued in mid-2012.

Fuel and Purchased Energy Cost Recovery Mechanisms — NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers.  Instead, under Wisconsin administrative rules, utilities must submit a forward-looking annual fuel cost plan to the PSCW for approval.  Once the PSCW approves the fuel cost plan, utilities must defer the amount of any fuel cost over-collection or under-collection in excess of a two percent annual tolerance band, for future rate recovery or refund.  Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW after opportunity for a hearing.  Rate recovery of deferred fuel cost is subject to an earnings test based on the utility’s most recently authorized ROE.  These rules first went into effect in January 2011.

NSP-Wisconsin’s wholesale electric rate schedules include a fuel clause adjustment to provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy.

NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, which are based on 12-month projections.  After each 12-month period, reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

PSCo

Solar*Rewards Program — In February 2011, PSCo filed to reduce the payments to customers installing on-site solar generation due to changes in market conditions resulting from the decrease in cost of solar energy.  In March 2011, PSCo entered into a settlement agreement with CPUC Staff, OCC, Colorado Solar Energy Industries Association, Solar Alliance, Western Resource Advocates, Colorado Governor’s Energy Office and Colorado Renewable Energy Society that limits the amount of customer sited solar generation that PSCo will purchase, caps the amount PSCo will spend on customer sited solar, and quickly shifts from up-front payments to pay-for-performance.  The settlement gives PSCo a presumption of prudence, for both the existing renewable energy standard adjustment (RESA) balance, and the future RESA balance if PSCo performs consistent with the acquisition terms of the settlement.  The CPUC approved the settlement and the program was re-opened in March 2011.

CACJA — The CACJA was signed into law in April 2010.  The CACJA required PSCo to file a comprehensive plan to reduce annual emissions of NOx by at least 70 to 80 percent or greater from 2008 levels by 2017 from the coal-fired generation identified in the plan.  The plan was required to consider both current and reasonably foreseeable CAA requirements and allows PSCo to propose emission controls, plant refueling, or plant retirement of at least 900 MW of coal-fired generating units in Colorado by Dec. 31, 2017.  The legislation further encourages PSCo to submit long-term gas contracts to the CPUC for approval.  The CACJA permits the CPUC to consider interim rate increases after Jan. 1, 2012, while the rate filing is pending and allows for multi-year rate plans.

In December 2010, the CPUC approved the following:

● Shutdown Cherokee Units 1 and 2 in 2011 and Cherokee Unit 3 (365 MW in total) by the end of 2015, after a new natural gas combined-cycle unit is built at Cherokee Station (569 MW);

● Fuel-switch Cherokee Unit 4 (352 MW) to natural gas by 2017;

● Shutdown Arapahoe Unit 3 (45 MW) and fuel-switch Unit 4 (111 MW) in 2014 to natural gas;

● Shutdown Valmont Unit 5 (186 MW) in 2017;

● Install SCR for controlling NOx and a scrubber for controlling SO2 on Pawnee Station in 2014;

● Install SCR on Hayden Unit 1 in 2015 and Hayden Unit 2 in 2016; and

● Convert Cherokee Unit 2 and Arapahoe Unit 3 to synchronous condensers to support the transmission system.

40

The CPUC provided for recovery on construction work in process (CWIP) in rate base in each rate case and deferred accounting of accelerated depreciation costs.  PSCo needs to make applications for detailed cost review before commencing each phase of the plan.  The CPUC also encouraged PSCo to hold stakeholder meetings to discuss issues around a multi-year rate plan.  In January 2011, the Colorado Air Quality Control Commission unanimously approved incorporation of the CACJA plan into Colorado’s regional haze state implementation plan (SIP).  See Note 3 and Note 5 to the consolidated financial statements for discussion.  In April 2011, the Colorado General Assembly approved legislation authorizing the regional haze SIP containing the CACJA plan.  Upon signature by the Governor of Colorado, the SIP (including the CACJA plan) will be sent to the EPA for incorporation into federal CAA regulations.  The total investment associated with the adopted plan is approximately $1.0 billion over the next seven years.  The rate impact of the proposed plan is expected to increase future bills on average by 2 percent annually.

In March 2011, PSCo filed an application for approval of the conversion of Cherokee Unit 2 to a synchronous condenser and notified the CPUC that it could maintain transmission system reliability without conversion of Arapahoe Unit 3.  In April 2011, PSCo filed for approval of the decommissioning of Cherokee 1 and 2 to provide space for the new combined-cycle plant.

Cameo Generating Station — In 2008, the CPUC approved PSCo’s request to retire the 73 MW Cameo coal-fired generating station at the end of 2011.  Cameo Station was retired at the end of 2010.  In February 2011, PSCo filed a plan for decommissioning, remediation, removal, and restoration at the site.  Only two parties (the OCC and gas intervenors) intervened and neither requested a hearing.  The matter is pending before the CPUC.

San Luis Valley-Calumet-Comanche Unit 3 Transmission Project — In May 2009, PSCo and Tri-State Generation and Transmission Association filed a joint application with the CPUC for a project for 230 KV and 345 KV line and substation construction.  The line is intended to assist in bringing solar power in the San Luis Valley to load.  The line was originally expected to be placed in-service in 2013; however, that appears unlikely now due to delays in the siting and permitting of the line.  Several landowners oppose this transmission line, including two large ranches.  In November 2010, the ALJ issued a recommended decision granting the CPCN but proposing a significant refund obligation if the line was not heavily utilized ten years after it was in service.  Several parties, including PSCo, filed exceptions to the recommended decision.  The CPUC deliberated on the exceptions to the recommended decision and granted the CPCN without the refund obligation recommended by the ALJ.  A written decision was issued on March 23, 2011.

SmartGridCity™ CPCN — As part of the PSCo 2010 electric rate case, the CPUC included recovery of the revenue requirements associated with $45 million of capital and $4 million of annual O&M costs incurred by PSCo to develop and operate SmartGridCity™, subject to refund, and ordered PSCo to file for a CPCN for that project.

In February 2011, the CPUC approved the CPCN and allowed recovery of approximately $28 million of the capital cost and 100 percent of the O&M costs and ordered PSCo to file for a rate reduction in April 2011 to reflect the lower level of capital in rate base.  The CPUC seeks additional information regarding the future plans to utilize SmartGridCity™ in an application to recover the additional capital.  PSCo believes that it will be able to satisfy that requirement.  In April 2011, PSCo filed to reduce its rates by approximately $2.0 million annually beginning in May 2011.

SPS

New Mexico Energy Efficiency Disincentive Rulemaking— During the 2008 New Mexico legislative session, increased energy efficiency goals and removal of disincentives were adopted.  In 2010, the NMPRC adopted an amended rule incorporating the legislative changes.  The rule had an interim mechanism that provides for recovery of disincentives and required utilities to file permanent rate design or other means of removing disincentives.

In July 2010, SPS filed its application to remove disincentives and requested direct lost margin recovery.  A final approval order was received in December 2010 totaling $3.3 million for 2010 and 2011.

Subsequently, SPS filed a plan to implement the rule by recovering both an incentive and disincentive amount.  SPS and NMPRC staff and several environmental groups reached a settlement that would allow for a combined recovery of disincentives and incentives of $2.0 million per year for the years 2012, 2013 and 2014 unless rates from a future SPS rate case (other than the currently pending rate case) become effective prior to the end of the 2014 calendar year, in which event, the stipulated recovery will apply only to those periods prior to the effective date from that rate case.  The New Mexico attorney general and the New Mexico Industrial Energy Consumers oppose the settlement.  A hearing in this case that focuses on the appropriate long-term mechanism was held in April 2011.

41

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of Xcel Energy’s utility subsidiaries, including enforcement of North American Electric Reliability Corporation (NERC) mandatory electric reliability standards.  State and local agencies have jurisdiction over many of Xcel Energy’s utility activities, including regulation of retail rates and environmental matters.  See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the Xcel Energy Annual Report on Form 10-K for the year ended Dec. 31, 2010.  In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

NERC Electric Reliability Standards Compliance

Compliance Audits and Self Reports

In November 2010, the NSP System (the electric production and transmission system of NSP-Minnesota is managed as an integrated system with that of NSP-Wisconsin, jointly referred to as the NSP System), PSCo and SPS filed self-reports with the Midwest Reliability Organization (MRO), the Western Electricity Coordinating Council (WECC) and SPP, respectively, regarding potential violations of certain NERC critical infrastructure protection standards (CIPS).  Additional self-reports of potential violations of CIPS standards were filed in January 2011.  Based on the issues identified with CIPS compliance, the utility subsidiaries submitted a mitigation plan that provides for a comprehensive review of its CIPS compliance programs.  Whether and to what extent penalties may be assessed against the utility subsidiaries for the issues identified and self-reported to date is unclear.

In February and March 2011, the NSP System was subject to a comprehensive triennial audit by the MRO regarding compliance with various NERC mandatory reliability standards, including CIPS.  The MRO found potential violations of seven standards; five are related to CIPS.  The written MRO reports are now being completed, and Xcel Energy anticipates challenging certain of the potential violations.  None of the potential violations is expected to result in a material penalty.

NERC Compliance Investigations

In September 2007, portions of the NSP System and transmission systems west and north of the NSP System briefly islanded from the rest of the Eastern Interconnection as a result of a series of transmission line outages.  In addition, service to approximately 790 MW of load was temporarily interrupted, primarily in Saskatchewan, Canada.  In late 2010, NERC transferred responsibility for completing the compliance investigation to the MRO.�� The final outcome of the compliance investigation, and whether and to what extent penalties for violations may be assessed, is unknown at this time.

In February 2010, the NERC notified NSP-Minnesota that it was commencing a non-public investigation of NSP-Minnesota maintenance practices associated with insulating oil levels in bulk electric system substations, as the result of an anonymous complaint received by the NERC.  NSP-Minnesota is cooperating with the investigation.  In February 2011, NERC transferred responsibility for completing the compliance investigation to the MRO.  The MRO reviewed the status of insulating oil levels during the triennial compliance audit in first quarter 2011.  The final outcome of the compliance investigation, and whether and to what extent the MRO may seek to impose penalties for alleged violations, is unknown at this time.

FERC Tie Line Investigation — In October 2007, the FERC Office of Enforcement, DOI, commenced a non-public investigation of the transmission service arrangements across the Lamar Tie Line, a transmission facility that connects PSCo and SPS.  In July 2008, the DOI issued a preliminary report alleging Xcel Energy violated certain FERC policies, rules and approved tariffs that could result in material penalties under the FERC penalty guidelines.  The report does not constitute a finding by the FERC, which may accept, modify or reject any or all of the preliminary conclusions set forth in the report.  Xcel Energy provided a response that disagreed with the preliminary report and demonstrated compliance with applicable standards.  In December 2010, the DOI initiated settlement negotiation with Xcel Energy regarding possible resolution of the non-public investigation.  The final outcome of the FERC DOI investigation and to what extent FERC may seek to impose penalties for alleged violations is unknown at this time. 

Environmental, Legal and Other Matters

See a discussion of environmental, legal and other matters at Note 6 to the consolidated financial statements.

42

Critical Accounting Policies and Estimates

Preparation of the consolidated financial statements and related disclosures in compliance with GAAP requires the application of accounting rules and guidance, as well as the use of estimates.  The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs.  These judgments could materially impact the consolidated financial statements and disclosures, based on varying assumptions.  In addition, the financial and operating environment also may have a significant effect on the operation of the business and on the results reported even if the nature of the accounting policies applied have not changed.  Item 7 — Management’s Discussion and Analysis, in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2010, includes a discussion of accounting policies and estimates that are most significant to the portrayal of Xcel Energy’s financial condition and results, and that require management’s most difficult, subjective or complex judgments.  Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions.  As of March 31, 2011, there have been no material changes to policies set forth in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2010.

Pending Accounting Changes

See a discussion of recently issued accounting pronouncements and pending accounting changes in Note 2 to the consolidated financial statements.

Derivatives, Risk Management and Market Risk

In the normal course of business, Xcel Energy and its subsidiaries are exposed to a variety of market risks as disclosed in Management’s Discussion and Analysis and in item 1A – Risk Factors in its Annual Report on Form 10-K for the year ended Dec. 31, 2010.  Market risk is the potential loss or gain that may occur as a result of changes in the market or fair value of a particular instrument or commodity.  All financial and commodity-related instruments, including derivatives, are subject to market risk.  See Note 8 to the consolidated financial statements for further discussions of market risks associated with derivatives.

Xcel Energy is exposed to the impact of changes in price for energy and energy related products, which is partially mitigated by Xcel Energy’s use of commodity derivatives.  Though no material non-performance risk currently exists with the counterparties to Xcel Energy’s commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties.  Distress in the financial markets may also impact the fair value of the debt and equity securities in the nuclear decommissioning trust fund and master pension trust, as well as Xcel Energy’s ability to earn a return on short-term investments of excess cash.  As of March 31, 2011, there have been no material changes to market risks from those set forth in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2010.

Commodity Price Risk — Xcel Energy’s utility subsidiaries are exposed to commodity price risk in their electric and natural gas operations.  Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various fuels used in generation and distribution activities.  Commodity price risk is also managed through the use of financial derivative instruments.  Xcel Energy’s risk management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists.

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.

Changes in the fair value of commodity trading contracts before the impacts of margin-sharing mechanisms were as follows:

	Three Months Ended March 31,
(Thousands of Dollars)		2011			2010
Fair value of commodity trading net contract assets outstanding at Jan. 1		$	20,249		$	9,628
Contracts realized or settled during the period			(1,668	)		(486	)
Commodity trading contract additions and changes during period			5,902			6,061
Fair value of commodity trading net contract assets outstanding at March 31		$	24,483		$	15,203

43

At March 31, 2011, the fair values by source for the commodity trading net asset balances were as follows:

	Futures / Forwards
			Maturity										Maturity			Total Futures/
	Source of		Less Than				Maturity			Maturity			Greater Than			Forwards
(Thousands of Dollars)	Fair Value		1 Year				1 to 3 Years			4 to 5 Years			5 Years			Fair Value
NSP-Minnesota		1		$	7,121			$	15,186		$	701		$	-		$	23,008
		2			(19	)			-			-			-			(19	)
PSCo		1			634				1,008			-			-			1,642
				$	7,736			$	16,194		$	701		$	-		$	24,631

	Options
			Maturity										Maturity
	Source of		Less Than				Maturity			Maturity			Greater Than			Total Options
(Thousands of Dollars)	Fair Value		1 Year				1 to 3 Years			4 to 5 Years			5 Years			Fair Value
NSP-Minnesota		2		$	(69	)		$	-		$	-		$	-		$	(69	)
PSCo		2		$	(79	)		$	-		$	-		$	-		$	(79	)
				$	(148	)		$	-		$	-		$	-		$	(148	)

1 — Prices actively quoted or based on actively quoted prices.

2 — Prices based on models and other valuation methods.  These represent the fair value of positions calculated using internal models when directly and indirectly quoted external prices or prices derived from external sources are not available.  Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms.  The models reflect management’s estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of commodity prices and contractual volumes.  Market price uncertainty and other risks also are factored into the models.

Normal purchases and sales transactions, as defined bythe accounting guidance for derivatives and hedging, hedge transactions and certain other long-term power purchase contracts are not included in the fair values by source tables as they are not recorded at fair value as part of commodity trading operations.

At March 31, 2011, a 10 percent increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $0.1 million, whereas a 10 percent decrease would decrease pretax income from continuing operations by approximately $0.3 million.

Xcel Energy’s short-term wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value at Risk (VaR).  VaR expresses the potential change in fair value on the outstanding transactions, contracts, and obligations over a particular period of time under normal market conditions.  The VaRs for NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis using a Monte Carlo simulation with a 95 percent confidence level and a one-day holding period, were as follows:

	As of
(Millions of Dollars)	March 31,		VaR Limit		Average		High		Low
2011	$	0.30	$	3.00	$	0.17	$	0.30	$	0.10
2010		0.42		5.00		0.39		0.77		0.11

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

At March 31, 2011, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense by approximately $5.3 million annually, or approximately $1.3 million per quarter.  See Note 8 to the consolidated financial statements for a discussion of Xcel Energy and its subsidiaries’ interest rate derivatives.

44

Xcel Energy also maintains a nuclear decommissioning fund, as required by the NRC.  The nuclear decommissioning fund is subject to interest rate risk and equity price risk.  At March 31, 2011, the fund was invested in a diversified portfolio of cash equivalents, debt securities, equity securities, and other funds.  These funds may be used only for activities related to nuclear decommissioning.  The accounting for nuclear decommissioning recognizes that costs are recovered through rates; therefore, fluctuations in equity prices or interest rates do not have an impact on earnings.

Credit Risk— Xcel Energy and its subsidiaries are also exposed to credit risk.  Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations.  Xcel Energy and its subsidiaries maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.

At March 31, 2011, a 10 percent increase in prices would have resulted in a net decrease in credit exposure of $85.7 million, while a decrease of 10 percent would have resulted in an increase in credit exposure of $73.3 million.

Xcel Energy and its subsidiaries conduct standard credit reviews for all counterparties.  Xcel Energy employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and other termination provisions that allow for offsetting of positive and negative exposures.  Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.  Distress in the financial markets could increase Xcel Energy’s credit risk.

Fair Value Measurements

Xcel Energy follows accounting and disclosure guidance on fair value measurements that contains a hierarchy for inputs used in measuring fair value and generally requires that the most observable inputs available be used for fair value measurements.  See Note 8 to the consolidated financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.

Commodity Derivatives — 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 and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at March 31, 2011.  Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues when necessary.  Credit risk adjustments for other commodity derivative instruments are deferred as OCI or regulatory assets and liabilities.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.  Xcel Energy also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities.  The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at March 31, 2011.

Commodity derivative assets and liabilities assigned to Level 3 consist primarily of FTRs, as well as forwards and options that are either long-term in nature or related to commodities and delivery points with limited observability.  Level 3 commodity derivative assets and liabilities represent immaterial percentages of total assets and liabilities measured at fair value at March 31, 2011.

Determining the fair value of FTRs requires numerous management forecasts that vary in observability, including various forward commodity prices, retail and wholesale demand, generation and resulting transmission system congestion.  Given the limited observability of management’s forecasts for several of these inputs, these instruments have been assigned a Level 3.  Level 3 commodity derivatives assets and liabilities include $2.7 million and $0.3 million of estimated fair values, respectively, for FTRs held at March 31, 2011.

Determining the fair value of certain commodity forwards and options can require management to make use of subjective forward price and volatility forecasts for commodities and locations with limited observability, or subjective forecasts which extend to periods beyond those readily observable on active exchanges or quoted by brokers.  When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3.  There were no Level 3 commodity forwards or options held at March 31, 2011.

Nuclear Decommissioning Fund — Nuclear decommissioning fund assets assigned to Level 3 consist of asset-backed and mortgage-backed securities.  To the extent appropriate, observable market inputs are utilized to estimate the fair value of these securities; however, less observable and subjective inputs are often significant to these valuations, including risk-based adjustments to the interest rate used to discount expected future cash flows, which include estimated prepayments of principal.  Therefore, estimated fair values for all asset-backed and mortgage-backed securities totaling $124.3 million in the nuclear decommissioning fund at March 31, 2011 (approximately 8.7 percent of total assets measured at fair value), are assigned to Level 3.  Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a nuclear decommissioning regulatory asset.

45

Liquidity and Capital Resources

Cash Flows

	Three Months Ended March 31,
(Millions of Dollars)	2011		2010
Cash provided by operating activities	$	659	$	552

Cash provided by operating activities increased by $107 million for the three months ended March 31, 2011, compared with the three months ended March 31, 2010. The increase was result of changes in working capital primarily due to changes in accounts payable related to timing, which were partially offset by changes in pension and employee benefit obligations mostly due to voluntary contributions of $134 million to Xcel Energy’s pension plans in January 2011.

	Three Months Ended March 31,
(Millions of Dollars)	2011			2010
Cash used in investing activities	$	(624	)	$	(460	)

Cash used in investing activities increased by $164 million for the three months ended March 31, 2011, compared with the three months ended March 31, 2010.This increase was due to higher capital expenditures, primarily at SPS at the Jones Plant site in Lubbock, Texas, as well as a deposit for progress payments made on the Merricourt Wind Project, which was subsequently terminated. The deposit was collected in April 2011.

	Three Months Ended March 31,
(Millions of Dollars)	2011			2010
Cash provided by financing activities	$	(49	)	$	(122	)

Cash used in financing activities decreased by $73 million for the three months ended March 31, 2011, compared with the three months ended March 31, 2010.  The decrease is primarily due to higher proceeds from short-term borrowings and lower repayments of long-term debt.

Capital Requirements

Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, preferred securities and hybrid securities to maintain desired capitalization ratios.

Regulation of Derivatives — In July 2010, President Obama signed financial reform legislation which provides for the regulation of derivative transactions amongst other provisions.  Provisions within the bill provide the Commodity Futures Trading Commission (CFTC) and SEC with expanded regulatory authority over derivative and swap transactions.  Regulations effected under this legislation could preclude or impede some types of over-the-counter energy commodity transactions and/or require clearing through regulated central counterparties, which could negatively impact the market for these transactions as well as result in extensive margin and fee requirements.  Additionally there may be material increased reporting requirements.  The bill contains provisions that should exempt certain derivatives end users from much of the clearing and margining requirements.  However, the CFTC is still developing the appropriate regulatory rules under the act and, at this time, it is not clear whether Xcel Energy will qualify for the exemption.  In addition, although the CFTC’s proposed rules would extend the end user exemption to margin requirements, they would impose a requirement to have credit support agreements in their place.  If Xcel Energy does not meet the end user exception, the margin requirements could be significant.  Xcel Energy expects the various definitions and rulemakings to be completed during 2011.  The full implications for Xcel Energy can not be determined until that time.

Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short–term to long duration fixed income securities, and alternative investments, including, private equity, real estate and commodity index investments.  In 2010, Xcel Energy voluntarily contributed $34 million to one of its pension plans.  In January 2011, Xcel Energy contributed $134 million, allocated across three of its pension plans.  The January 2011 contribution raised the overall funded status from 84 percent at Dec. 31, 2010 to 88 percent with all other pension assumptions remaining constant.  Based on updated valuation results received in March 2011 for the NCE Non-Bargaining Pension Plan, Xcel Energy plans to make a required contribution of $3.3 million to the NCE Non-Bargaining Pension Plan in mid-2011.  Projected pension funding contributions for 2012, which will be dependent on several factors including realized asset performance, future discount rate, IRS and legislative initiatives as well as other actuarial assumptions, are estimated to range between $150 million to $175 million.

46

Capital Sources

Short-Term Funding Sources — Xcel Energy uses a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit.  The amount and timing of short-term funding needs depend in large part on financing needs for construction expenditures, working capital and dividend payments.

Short-Term Investments — Xcel Energy, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating accounts with Wells Fargo Bank.  At March 31, 2011, approximately $19.9 million of cash was held in these liquid operating accounts.

Commercial Paper — Xcel Energy, NSP-Minnesota, PSCo, SPS and NSP-Wisconsin each have individual commercial paper programs.  NSP-Wisconsin received regulatory approval to initiate a commercial paper program in the first quarter of 2011.  The authorized levels for these commercial paper programs are:

● $800 million for Xcel Energy;

● $700 million for PSCo;

● $500 million for NSP-Minnesota;

● $300 million for SPS; and

● $150 million for NSP-Wisconsin.

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

Credit Facilities — During March of 2011, NSP-Minnesota, NSP-Wisconsin, PSCo, SPS and Xcel Energy executed new 4-year credit agreements.  The total capacity of the credit facilities increased approximately $273 million to $2.45 billion.  As of April 25, 2011, Xcel Energy and its utility subsidiaries had the following committed credit facilities available to meet its liquidity needs:

(Millions of Dollars)	Facility(b)			Drawn (a)		Available		Cash		Liquidity
Xcel Energy – Holding Company		$	800.0	$	323.1	$	476.9	$	2.7	$	479.6
PSCo			700.0		89.6		610.4		1.3		611.7
NSP-Minnesota			500.0		7.1		492.9		0.3		493.2
SPS			300.0		59.0		241.0		0.5		241.5
NSP-Wisconsin			150.0		44.0		106.0		0.2		106.2
Total		$	2,450.0	$	522.8	$	1,927.2	$	5.0	$	1,932.2

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

(b) These credit facilities expire in March 2015.

Money Pool — Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals.  The utility money pool allows for short-term investments in and borrowings from the utility subsidiaries and investments from the Holding Company to the utility subsidiaries at market-based interest rates.  The money pool balances are eliminated during consolidation.

The utility money pool arrangement does not allow the Holding Company to borrow from the utility subsidiaries.  NSP-Minnesota, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions.  NSP-Wisconsin does not participate in the money pool.

Long-Term Borrowings — See Note 7 to the consolidated financial statements for further discussion on borrowings.

47

Financing Plans — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund construction programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes.  In addition to the periodic issuance and repayment of short-term debt, Xcel Energy and its utility subsidiaries’ financing plans are as follows:

● PSCo may issue approximately $250 million of first mortgage bonds during the second half of 2011.

● SPS may issue approximately $150 million of bonds in the summer of 2011.

● Xcel Energy also anticipates issuing approximately $75 million of equity through the Dividend Reinvestment and Stock Purchase Plan (DSPP) and various benefit programs in 2011.

Financing plans are subject to change, depending on capital expenditures, internal cash generation, market conditions and other factors.

Off-Balance-Sheet Arrangements

Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Earnings Guidance

Xcel Energy’s 2011 ongoing earnings guidance is $1.65 to $1.75 per share.  Key assumptions related to ongoing earnings are detailed below:

● Normal weather patterns are experienced for the year.

● Weather-adjusted retail electric utility sales, adjusted for the sale of the Lubbock distribution assets, are projected to grow approximately 1.0 to 1.3 percent.

● Weather-adjusted retail firm natural gas sales are projected to decline 1 percent.

● Constructive outcomes in all rate case and regulatory proceedings.

● Rider revenue recovery is projected to be relatively flat.

● O&M expenses are projected to increase up to 4 percent.

● Depreciation expense is projected to increase $50 million to $60 million.

● Interest expense is projected to increase approximately $10 million.

● AFUDC — equity is projected to be relatively flat.

● The effective tax rate is projected to be approximately 34 percent to 36 percent.

● Average common stock and equivalents are projected to be approximately 485 million shares.

Item 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Management’s Discussion and Analysis under Item 2.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of March 31, 2011, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in Xcel Energy’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting.

48

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

In the normal course of business, various lawsuits and claims have arisen against Xcel Energy.  After consultation with legal counsel, Xcel Energy has recorded an estimate of the probable cost of settlement or other disposition for such matters.

Legal Contingencies

Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the U.S. Department of Energy (DOE) failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the DOE and NSP-Minnesota.  At trial, NSP-Minnesota claimed damages in excess of $100 million through Dec. 31, 2004.  In September 2007, the court awarded NSP-Minnesota $116.5 million in damages.  In February 2008, the DOE filed an appeal to the U.S. Court of Appeals for the Federal Circuit, and NSP-Minnesota cross-appealed on the cost of capital issue.  The Court heard oral arguments on April 4, 2011.  It is uncertain when the Court will issue a decision.  Results of the judgment will not be recorded in earnings until the appeal, regulatory treatment and amounts to be shared with ratepayers have been resolved.  Given the uncertainties, it is unclear as to how much, if any, of this judgment will ultimately have an effect on Xcel Energy’s consolidated results of operations, cash flows or financial position.

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

Additional Information

See Notes 5 and 6 to the consolidated financial statements for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference.  Reference also is made to Item 3 and Notes 13 and 14 of Xcel Energy’s consolidated financial statements in its Annual Report on Form 10-K for the year ended Dec. 31, 2010 for a description of certain legal proceedings presently pending.

Item 1A — RISK FACTORS

Except to the extent updated or described below, Xcel Energy’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2010, which is incorporated herein by reference.

Operational Risks

Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.

NSP-Minnesota’s two nuclear stations, Prairie Island and Monticello, subject it to the risks of nuclear generation, which include:

● The risks associated with use of radioactive material in the production of energy, the management, handling, storage and disposal of these radioactive materials and the current lack of a long-term disposal solution for radioactive materials;

● Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and

● Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of licensed lives.

The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities.  In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved.  Revised NRC safety requirements could necessitate substantial capital expenditures or a substantial increase in operating expenses at NSP-Minnesota’s nuclear plants.  In addition, the Institute for Nuclear Power Operations reviews NSP-Minnesota’s nuclear operations and nuclear generation facilities.  Compliance with the Institute for Nuclear Power Operations’ recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.

49

If an incident did occur, it could have a material adverse effect on our results of operations or financial condition.  Furthermore, the non-compliance of other nuclear facilities operators with applicable regulations or the occurrence of a serious nuclear incident at other facilities could result in increased regulation of the industry as a whole, which could then increase NSP-Minnesota’s compliance costs and impact the results of operations of its facilities.  The recent events at the nuclear facilities in Fukushima, Japan could result in increased regulation of the nuclear generation industry as a whole, and additional requirements with respect to emergency planning and demonstrated ability to operate nuclear facilities in the event of natural disasters or other events.  This increased regulation could increase NSP-Minnesota’s compliance costs and impact the results of operations of its nuclear facilities.  Furthermore, these events could cause increased regulatory review and scrutiny by the NRC which could lead to delays in the process for obtaining required regulatory reviews and approvals.

NSP-Wisconsin’s production and transmission system is operated on an integrated basis with NSP-Minnesota’s production and transmission system, and NSP-Wisconsin may be subject to risks associated with NSP-Minnesota’s nuclear generation.

Item 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

	Issuer Purchases of Equity Securities
Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
Jan. 1, 2011 — Jan. 31, 2011(a)		16,783	$	24.00		-		-
Feb. 1, 2011 — Feb. 28, 2011		-		-		-		-
March 1, 2011 — March 31, 2011 (b)		10,625		23.75		-		-
Total		27,408				-		-

(a) Xcel Energy or one of its agents periodically purchases common shares in order to satisfy obligations under the Stock Equivalent Plan for Non-Employee Directors.

(b) The repurchase of shares noted in the table above was made pursuant to the Xcel Energy Executive Annual Incentive Award Plan. The shares were returned to Xcel Energy on behalf of some of the participants receiving an incentive award of common shares to effectuate the payment of federal and state income taxes on the award.

50

Item 6 — EXHIBITS

* Indicates incorporation by reference

t    Furnished, herewith, not filed.  Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

3.01*	Restated Articles of Incorporation of Xcel Energy, as amended on May 21, 2008 (Exhibit 3.01 to Form 10-Q for the quarter ended June 30, 2008 (file no. 001-03034)).
3.02*	Restated By-Laws of Xcel Energy (Exhibit 3.01 to Form 8-K dated Aug. 12, 2008 (file no. 001-03034)).
10.01*	Credit Agreement, dated as of March 17, 2011 among Xcel Energy Inc., as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Capital, the investment banking division of Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Exhibit 99.01 to Form 8-K of Xcel Energy, file number 001-03034, dated March 23, 2011).
10.02*	Credit Agreement, dated as of March 17, 2011 among NSP-Minnesota, a Minnesota corporation, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Capital, the investment banking division of Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Exhibit 99.02 to Form 8-K of Xcel Energy, file number 001-03034, dated March 23, 2011).
10.03*	Credit Agreement, dated as of March 17, 2011 among NSP-Wisconsin, a Wisconsin corporation, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Capital, the investment banking division of Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Exhibit 99.03 to Form 8-K of Xcel Energy, file number 001-03034, dated March 23, 2011).
10.04*	Credit Agreement, dated as of March 17, 2011 among PSCo as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Capital, the investment banking division of Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Exhibit 99.04 to Form 8-K of Xcel Energy, file number 001-03034, dated March 23, 2011).
10.05*	Credit Agreement, dated as of March 17, 2011 among SPS, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Capital, the investment banking division of Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Exhibit 99.05 to Form 8-K of Xcel Energy, file number 001-03034, dated March 23, 2011).
10.06*	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated effective Feb. 23, 2011 (Appendix A to the Xcel Energy Definitive Proxy Statement (file no. 001-03034) filed April 5, 2011).
31.01	Principal Executive Officer’s and Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101 t	The following materials from Xcel Energy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 are formatted in XBRL (eXtensible Business Reporting Language):  (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Cash Flow, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Stockholder’s Equity and Comprehensive Income, (v) Notes to Condensed Consolidated Financial Statements, and (vi) document and entity information.

51

SIGNATURES

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

		XCEL ENERGY INC.
April 29, 2011	By:	/s/ TERESA S. MADDEN
		Teresa S. Madden
		Vice President and Controller
		(Principal Accounting Officer)
		/s/ DAVID M. SPARBY
		David M. Sparby
		Vice President and Chief Financial Officer
		(Principal Financial Officer)

52