Edgar Filing: XCEL ENERGY INC

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2013

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

Commission File Number: 001-3034

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). £Yes 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 26, 2013
Common Stock, $2.50 par value		497,239,284 shares

TABLE OF CONTENTS

PART I		FINANCIAL INFORMATION		3
	Item 1 —	Financial Statements (unaudited)		3
			CONSOLIDATED STATEMENTS OF INCOME	3
			CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME	4
			CONSOLIDATED STATEMENTS OF CASH FLOWS	5
			CONSOLIDATED BALANCE SHEETS	6
			CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY	7
			NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	8
	Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
	Item 3 —	Quantitative and Qualitative Disclosures about Market Risk		51
	Item 4 —	Controls and Procedures		51
PART II		OTHER INFORMATION		51
	Item 1 —	Legal Proceedings		51
	Item 1A —	Risk Factors		51
	Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds		52
	Item 4 —	Mine Safety Disclosures		52
	Item 5 —	Other Information		52
	Item 6 —	Exhibits		52
SIGNATURES				54
		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 (PSCo); and Southwestern Public Service Company (SPS). Xcel Energy Inc. and its consolidated subsidiaries are also referred to herein as Xcel Energy. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries. Additional information on the wholly owned subsidiaries is available on various filings with the Securities and Exchange Commission (SEC).

Table of Contents

PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands, except per share data)

	Three Months Ended March 31
	2013			2012
Operating revenues
Electric	$	2,092,196		$	1,936,782
Natural gas		669,596			621,035
Other		21,057			20,262
Total operating revenues		2,782,849			2,578,079

Operating expenses
Electric fuel and purchased power		925,043			863,980
Cost of natural gas sold and transported		439,375			417,946
Cost of sales — other		8,411			7,304
Operating and maintenance expenses		529,231			510,684
Conservation and demand side management program expenses		64,032			63,707
Depreciation and amortization		248,706			228,672
Taxes (other than income taxes)		113,427			105,624
Total operating expenses		2,328,225			2,197,917

Operating income		454,624			380,162

Other income, net		3,922			3,737
Equity earnings of unconsolidated subsidiaries		7,577			7,158
Allowance for funds used during construction — equity		19,754			13,450

Interest charges and financing costs
Interest charges — includes other financing costs of $5,809 and $6,080, respectively		139,613			151,830
Allowance for funds used during construction — debt		(8,758	)		(6,607	)
Total interest charges and financing costs		130,855			145,223

Income from continuing operations before income taxes		355,022			259,284
Income taxes		118,434			75,515
Income from continuing operations		236,588			183,769
(Loss) income from discontinued operations, net of tax		(18	)		124
Net income	$	236,570		$	183,893

Weighted average common shares outstanding:
Basic		489,781			487,360
Diluted		490,531			487,995

Earnings per average common share:
Basic	$	0.48		$	0.38
Diluted		0.48			0.38

Cash dividends declared per common share	$	0.27		$	0.26

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2013			2012

Net income	$	236,570		$	183,893

Other comprehensive (loss) income

Pension and retiree medical benefits:
Amortization of (gains) losses included in net periodic benefit cost, net of tax of $2,503 and $622, respectively		(639	)		895

Derivative instruments:
Net fair value increase, net of tax of $12 and $16,491, respectively		13			25,392
Reclassification of (gains) losses to net income, net of tax of $1,429 and $156, respectively		(305	)		181
		(292	)		25,573

Marketable securities:
Net fair value (decrease) increase, net of tax of $(18) and $36, respectively		(36	)		52

Other comprehensive (loss) income		(967	)		26,520
Comprehensive income	$	235,603		$	210,413

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2013			2012
Operating activities
Net income	$	236,570		$	183,893
Remove loss (income) from discontinued operations		18			(124	)
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		253,004			233,097
Conservation and demand side management program amortization		1,712			1,882
Nuclear fuel amortization		27,522			26,000
Deferred income taxes		130,662			167,426
Amortization of investment tax credits		(1,657	)		(1,552	)
Allowance for equity funds used during construction		(19,754	)		(13,450	)
Equity earnings of unconsolidated subsidiaries		(7,577	)		(7,158	)
Dividends from unconsolidated subsidiaries		9,539			8,028
Share-based compensation expense		8,167			3,883
Net realized and unrealized hedging and derivative transactions		217			7,133
Changes in operating assets and liabilities:
Accounts receivable		(72,205	)		(52,643	)
Accrued unbilled revenues		76,602			197,330
Inventories		87,865			143,873
Other current assets		(51,203	)		(71,547	)
Accounts payable		5,311			(202,649	)
Net regulatory assets and liabilities		88,572			61,872
Other current liabilities		20,318			17,711
Pension and other employee benefit obligations		(181,091	)		(180,030	)
Change in other noncurrent assets		24,576			(38,806	)
Change in other noncurrent liabilities		5,160			(6,686	)
Net cash provided by operating activities		642,328			477,483

Investing activities
Utility capital/construction expenditures		(752,251	)		(497,218	)
Proceeds from insurance recoveries		23,500			-
Allowance for equity funds used during construction		19,754			13,450
Purchases of investments in external decommissioning fund		(586,239	)		(213,618	)
Proceeds from the sale of investments in external decommissioning fund		584,948			213,618
Investment in WYCO Development LLC		(231	)		(172	)
Change in restricted cash		-			86,232
Other, net		(2,745	)		(1,304	)
Net cash used in investing activities		(713,264	)		(399,012	)

Financing activities
(Repayments of) proceeds from short-term borrowings, net		(177,000	)		120,000
Proceeds from issuance of long-term debt		494,282			745
Repayments of long-term debt, including reacquisition premiums		(251,367	)		(758	)
Proceeds from issuance of common stock		160,084			1,598
Repurchase of common stock		-			(18,529	)
Purchase of common stock for settlement of equity awards		-			(23,307	)
Dividends paid		(124,426	)		(119,162	)
Net cash provided by (used in) financing activities		101,573			(39,413	)

Net change in cash and cash equivalents		30,637			39,058
Cash and cash equivalents at beginning of period		82,323			60,684
Cash and cash equivalents at end of period	$	112,960		$	99,742

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(153,498	)	$	(156,275	)
Cash received (paid) for income taxes, net		17,939			(1,173	)
Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable	$	256,530		$	224,316
Issuance of common stock for reinvested dividends and 401(k) plans		18,791			18,815

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands, except share and per share data)

	March 31, 2013			Dec. 31, 2012
Assets
Current assets
Cash and cash equivalents	$	112,960		$	82,323
Accounts receivable, net		789,209			718,046
Accrued unbilled revenues		586,761			663,363
Inventories		447,709			535,574
Regulatory assets		369,206			352,977
Derivative instruments		59,554			69,013
Deferred income taxes		93,193			32,528
Prepayments and other		246,079			171,315
Total current assets		2,704,671			2,625,139

Property, plant and equipment, net		24,219,231			23,809,348

Other assets
Nuclear decommissioning fund and other investments		1,663,648			1,617,865
Regulatory assets		2,711,881			2,762,029
Derivative instruments		111,168			126,297
Other		177,076			200,008
Total other assets		4,663,773			4,706,199
Total assets	$	31,587,675		$	31,140,686

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	6,929		$	258,155
Short-term debt		425,000			602,000
Accounts payable		932,547			959,093
Regulatory liabilities		193,658			168,858
Taxes accrued		415,081			334,441
Accrued interest		135,532			162,494
Dividends payable		133,238			131,748
Derivative instruments		30,762			32,482
Other		253,770			287,802
Total current liabilities		2,526,517			2,937,073

Deferred credits and other liabilities
Deferred income taxes		4,643,378			4,434,909
Deferred investment tax credits		81,674			82,761
Regulatory liabilities		1,077,606			1,059,939
Asset retirement obligations		1,741,707			1,719,796
Derivative instruments		230,272			242,866
Customer advances		259,200			252,888
Pension and employee benefit obligations		979,520			1,163,265
Other		250,679			229,207
Total deferred credits and other liabilities		9,264,036			9,185,631

Commitments and contingencies
Capitalization
Long-term debt		10,642,009			10,143,905
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 494,755,061 and 487,959,516 shares outstanding at March 31, 2013 and Dec. 31, 2012, respectively		1,236,888			1,219,899
Additional paid in capital		5,515,513			5,353,015
Retained earnings		2,516,332			2,413,816
Accumulated other comprehensive loss		(113,620	)		(112,653	)
Total common stockholders’ equity		9,155,113			8,874,077
Total liabilities and equity	$	31,587,675		$	31,140,686

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)

(amounts in thousands)

	Common Stock Issued
													Accumulated			Total
													Other			Common
							Additional Paid			Retained			Comprehensive			Stockholders'
	Shares			Par Value			In Capital			Earnings			Loss			Equity
Three Months Ended March 31, 2013 and 2012
Balance at Dec. 31, 2011		486,494		$	1,216,234		$	5,327,443		$	2,032,556		$	(94,035	)	$	8,482,198
Comprehensive income:
Net income											183,893						183,893
Other comprehensive income														26,520			26,520
Comprehensive income																	210,413
Dividends declared:
Common stock											(127,174	)					(127,174	)
Issuances of common stock		1,142			2,855			2,288									5,143
Repurchase of common stock		(700	)		(1,750	)		(16,779	)								(18,529	)
Purchase of common stock for settlement of equity awards								(23,307	)								(23,307	)
Share-based compensation								8,927									8,927
Balance at March 31, 2012		486,936		$	1,217,339		$	5,298,572		$	2,089,275		$	(67,515	)	$	8,537,671

Balance at Dec. 31, 2012		487,960		$	1,219,899		$	5,353,015		$	2,413,816		$	(112,653	)	$	8,874,077
Comprehensive income:
Net income											236,570						236,570
Other comprehensive loss														(967	)		(967	)
Comprehensive income																	235,603
Dividends declared:
Common stock											(134,054	)					(134,054	)
Issuances of common stock		6,795			16,989			151,845									168,834
Share-based compensation								10,653									10,653
Balance at March 31, 2013		494,755		$	1,236,888		$	5,515,513		$	2,516,332		$	(113,620	)	$	9,155,113

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of Xcel Energy Inc. and its subsidiaries as of March 31, 2013 and Dec. 31, 2012; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three months ended March 31, 2013 and 2012; and its cash flows for the three months ended March 31, 2013 and 2012. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2013 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, 2012 balance sheet information has been derived from the audited 2012 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2012. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2012, filed with the SEC on Feb. 22, 2013. Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1.	Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2012, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2.	Accounting Pronouncements

Recently Adopted

Balance Sheet Offsetting — In December 2011, the Financial Accounting Standards Board (FASB) issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (Accounting Standards Update (ASU) No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. In January 2013, the FASB issued Balance Sheet (Topic 210) – Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU No. 2013-01) to clarify the specific instruments that should be considered in these disclosures. These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and were effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods. Xcel Energy implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements. See Note 8 for the required disclosures.

Comprehensive Income Disclosures — In February 2013, the FASB issued Comprehensive Income (Topic 220) — Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU No. 2013-02), which requires detailed disclosures regarding changes in components of accumulated other comprehensive income and amounts reclassified out of accumulated other comprehensive income. These disclosure requirements do not change how net income or comprehensive income are presented in the consolidated financial statements. These disclosure requirements were effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting periods. Xcel Energy implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements. See Note 13 for the required disclosures.

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3.	Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2013			Dec. 31, 2012
Accounts receivable, net
Accounts receivable	$	839,752		$	769,440
Less allowance for bad debts		(50,543	)		(51,394	)
	$	789,209		$	718,046

(Thousands of Dollars)	March 31, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	216,438	$	213,739
Fuel		171,121		189,425
Natural gas		60,150		132,410
	$	447,709	$	535,574

(Thousands of Dollars)	March 31, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	28,471,083		$	28,285,031
Natural gas plant		3,871,653			3,836,335
Common and other property		1,478,221			1,480,558
Plant to be retired (a)		141,038			152,730
Construction work in progress		2,136,733			1,757,189
Total property, plant and equipment		36,098,728			35,511,843
Less accumulated depreciation		(12,216,164	)		(12,048,697	)
Nuclear fuel		2,108,788			2,090,801
Less accumulated amortization		(1,772,121	)		(1,744,599	)
	$	24,219,231		$	23,809,348

(a)

In 2010, in response to the Clean Air Clean Jobs Act (CACJA), the Colorado Public Utilities Commission (CPUC) approved the early retirement of Cherokee Units 1, 2 and 3, Arapahoe Unit 3 and Valmont Unit 5 between 2011 and 2017. In 2011, Cherokee Unit 2 was retired and in 2012, Cherokee Unit 1 was retired. Amounts are presented net of accumulated depreciation.

4.	Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2012 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 2008 federal income tax return expired in September 2012. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011. As of March 31, 2013, the IRS had not proposed any material adjustments to tax years 2010 and 2011.

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, 2013, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows:

State		Year
Colorado		2006
Minnesota		2009
Texas		2008
Wisconsin		2008

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In the fourth quarter of 2012, the state of Colorado commenced an examination of tax years 2006 through 2009. In the first quarter of 2013, the state of Wisconsin commenced an examination of tax years 2009 through 2011. As of March 31, 2013, no material adjustments had been proposed for either of these audits. There are currently no other state income tax audits in progress.

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 benefit is as follows:

(Millions of Dollars)	March 31, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	7.0	$	4.7
Unrecognized tax benefit — Temporary tax positions		30.2		29.8
Total unrecognized tax benefit	$	37.2	$	34.5

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

(Millions of Dollars)		March 31, 2013				Dec. 31, 2012
NOL and tax credit carryforwards		$	(36.1	)		$	(33.5	)

It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state audits progress. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $35 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at March 31, 2013 and Dec. 31, 2012 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2013 or Dec. 31, 2012.

5.	Rate Matters

Except to the extent noted below, the circumstances set forth in Note 12 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2012 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

NSP-Minnesota

Pending Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)

Base Rate

NSP-Minnesota – Minnesota 2012 Electric Rate Case — In November 2012, NSP-Minnesota filed a request with the MPUC to increase electric rates approximately $285 million, or 10.7 percent. The rate filing was based on a 2013 forecast test year, a requested return on equity (ROE) of 10.6 percent, an average electric rate base of approximately $6.3 billion and an equity ratio of 52.56 percent. In January 2013, interim rates of approximately $251 million became effective, subject to refund.

On Feb. 28, 2013, intervening parties filed direct testimony proposing modifications to NSP-Minnesota’s rate request. The Minnesota Department of Commerce (DOC) recommended an increase of approximately $93.6 million, based on a recommended ROE of 10.24 percent and an equity ratio of 52.56 percent. Seven other intervenors filed testimony recommending various adjustments, some similar to the DOC, but no other party made a comprehensive analysis of all rate case elements. See the summary of DOC recommendations below.

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On March 25, 2013, NSP-Minnesota filed rebuttal testimony and revised the requested annual revenue increase to approximately $219.7 million, or 8.23 percent, based on an ROE of 10.6 percent, a rate base of approximately $6.3 billion and an equity ratio of 52.56 percent. The updated request reflects alternate proposals in several key areas including deferral and removal of certain costs related to Sherco 3 and to Monticello, as well as removal of costs for cancellation of the Prairie Island Extended Power Uprate (EPU) project. Additional adjustments were made for compensation and benefits, amortization of pension market losses and Black Dog remediation costs. NSP-Minnesota’s updated request also reflects more recent information on property taxes and sales forecast, as well as data corrections to the original filing.

On April 12, 2013, intervenors including the DOC, Office of Attorney General (OAG), Minnesota Chamber (MCC), Xcel Large Industrials (XLI), Commercial Group, Industrial, Commercial and Institutional Customers, and Energy Cents Coalition filed surrebuttal testimony. The DOC recommended a revenue increase of $89.6 million, based on a 9.83 percent ROE, an average electric rate base of approximately $6.1 billion and an equity ratio of 52.56 percent. The following table summarizes the effect of the DOC’s recommendations on NSP-Minnesota’s original request:

(Millions of Dollars)	DOC Direct Testimony February 2013			DOC Surrebuttal Testimony April 2013
NSP-Minnesota's original request	$	285		$	285
ROE		(20	)		(44	)
Sherco Unit 3		(39	)		(44	)
Reduced recovery for the nuclear plants		(9	)		(5	)
Elimination of certain incentive compensation		(25	)		(20	)
Increase to the sales forecast		(24	)		(26	)
Reduced recovery of pension		(25	)		(25	)
Employee benefits		(11	)		(6	)
Other, net		(38	)		(25	)
DOC recommendation	$	94		$	90

In its surrebuttal testimony, the OAG recommends, among other things, no recovery for the Prairie Island EPU project, stating it should have been written off in 2012 when cancellation was approved by the MPUC on Dec. 20, 2012. The DOC is also not supportive of recovery of the Prairie Island EPU cancelled plant costs, but identifies requirements for the next case if deferral is allowed. The OAG suggests pension recovery in rates exceeds benefit payout because of changes made to benefit plans and recommends correction for an alleged over-collection of funds to pay for future benefits which may never be paid out. The OAG supports the DOC in adjustments to recovery of annual incentive compensation and does not find NSP-Minnesota’s Sherco 3 proposal warranted. Other intervenors maintained their primary positions with various adjustments and recommendations for class responsibility and rate design. XLI and MCC opposed recovery of Sherco 3 costs and Monticello EPU costs.

Hearings were held in April and NSP-Minnesota revised its rate request to approximately $215.4 million to reflect updated property tax information and other adjustments. Also at the hearings, the DOC’s recommendation was revised to approximately $98.6 million, largely to reflect updated information. NSP-Minnesota has recognized a liability representing its best estimate of any refund obligation.

Next steps in the procedural schedule are expected to be as follows:

●

Initial Brief – May 15, 2013

●

Reply Brief and Findings of Fact – May 30, 2013

●

Administrative Law Judge (ALJ) Report – July 3, 2013

●

MPUC Order – Anticipated by September 2013

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

Base Rate

NSP-Minnesota – North Dakota 2012 Electric Rate Case — In December 2012, NSP-Minnesota filed a request with the NDPSC to increase annual retail electric rates approximately $16.9 million, or 9.25 percent. The rate filing is based on a 2013 forecast test year, a requested ROE of 10.6 percent, an electric rate base of approximately $377.6 million and an equity ratio of 52.56 percent. In January 2013, the NDPSC approved an interim electric increase of $14.7 million, effective Feb. 16, 2013, subject to refund.

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Next steps in the procedural schedule are expected to be as follows:

●

Staff/Intervenor Direct Testimony – July 12, 2013

●

Rebuttal Testimony – Aug. 12, 2013

●

Technical Hearings – Aug. 27-28, 2013

●

Initial Briefs – Sept. 20, 2013

●

Reply Briefs/Proposed Findings – October 2013

A final NDPSC decision on the case is expected in the fourth quarter of 2013.

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

Base Rate

NSP-Minnesota – South Dakota 2012 Electric Rate Case — In June 2012, NSP-Minnesota filed a request with the SDPUC to increase electric rates by $19.4 million annually. The request was based on a 2011 historic test year adjusted for known and measurable changes, a requested ROE of 10.65 percent, an average rate base of $367.5 million and an equity ratio of 52.89 percent. Interim rates of $19.4 million went into effect on Jan. 1, 2013, subject to refund.

In March 2013, NSP-Minnesota and the SDPUC Staff reached a settlement agreement that provides for a base rate increase of approximately $11.6 million and the implementation of a new rider to recover an additional $3.7 million for certain capital projects and incremental property taxes. Combined, the overall revenue increase for 2013 is approximately $15.3 million, or 9.1 percent. The rider is subject to true-up for actual costs and is projected to provide incremental revenue of $2.6 million in 2014. The settlement agreement also includes a moratorium on base rate increases, effective until Jan. 1, 2015. The settlement was approved by the SDPUC on April 9, 2013. Implementation of new rates and the rider began on May 1, 2013.

PSCo

Pending and Recently Concluded Regulatory Proceedings — CPUC

Base Rate

PSCo – Colorado 2013 Gas Rate Case — In December 2012, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas rates by $48.5 million in 2013 with subsequent step increases of $9.9 million in 2014 and $12.1 million in 2015. The request is based on a 2013 forecast test year, a 10.5 percent ROE, a rate base of $1.3 billion and an equity ratio of 56 percent. PSCo is requesting an extension of its Pipeline System Integrity Adjustment (PSIA) rider mechanism to collect the costs associated with its pipeline integrity efforts, including accelerated system renewal projects. PSCo estimates that the PSIA will increase by $26.8 million in 2014 with a subsequent step increase of $24.7 million in 2015 in addition to the proposed changes in base rate revenue. In conjunction with the multi-year base rate step increases, PSCo is proposing a stay-out provision and an earnings test through the end of 2015 with a commitment to file a rate case to implement revised rates on Jan. 1, 2016.

In January 2013, the CPUC suspended the tariff filing and set the case for hearing. In order to accommodate the procedural schedule, rates will go into effect as filed on Aug. 10, 2013, subject to refund for the difference between the filed rates and the rates approved in the final CPUC order in the case.

On April 3, 2013, four parties filed answer testimony in the natural gas case. The CPUC Staff and Office of Consumer Counsel (OCC) recommended changes to the level of integrity management costs moved from the PSIA rider to base rates. For clarity, PSCo will present base rate recommendations relative to deficiencies without the PSIA revenues to isolate the base rate impacts of the recommendations. PSCo’s 2013 deficiency based on a Forecasted Test Year (FTY) net of PSIA changes was $45 million for 2013 and the revenue deficiency was $28.3 million based on a Historic Test Year (HTY).

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The CPUC Staff recommended a rate reduction of $14.4 million, based on a HTY, an ROE of 9 percent and an equity ratio of 52 percent and other adjustments. The OCC recommended a rate increase of $0.5 million based on a HTY, an ROE of 9 percent and equity ratio of 51.03 percent and other adjustments. While the OCC did not recommend that the CPUC set rates using a FTY, they did calculate a revenue deficiency of $12.4 million for 2013. No other intervenor made ROE recommendations or specific recommendations regarding the revenue deficiency. The major adjustments to the test year proposed by the CPUC Staff and OCC are presented below.

(Millions of Dollars)	CPUC Staff			OCC
PSCo deficiency based on a HTY	$	28.3		$	28.3
ROE and capital structure adjustments		(20.8	)		(20.0	)
Move to a 13 month average from year end rate base		(5.7	)		(3.2	)
Remove pension asset		(5.9	)		-
Remove incentive compensation		(3.5	)		(0.2	)
Challenge known and measurable		-			(9.0	)
Eliminate depreciation annualization		-			(1.8	)
Revenue adjustments		(4.1	)		(1.4	)
Resulting tax impacts		1.5			4.7
Other adjustments		(4.2	)		3.1
Recommendation	$	(14.4	)	$	0.5

On April 26, 2013, the CPUC Staff filed supplemental testimony recommending an additional net disallowance of $1.6 million for adjustments and corrections.

On April 29, 2013, PSCo filed rebuttal testimony and revised its requested annual rate increase to $44.8 million for 2013, $9.0 million for 2014 and $10.9 million for 2015, based on an ROE of 10.3 percent. PSCo refutes the recommendations of the CPUC Staff and the OCC to disallow known and measurable adjustments and otherwise change regulatory precedent including moving from end of year rate base to average rate base for a HTY, removing the pension asset, removing incentive compensation and moving to an imputed capital structure. PSCo agreed to recover approximately $3.5 million of revenue requirement in the PSIA, rather than through base rates and accepted the CPUC Staff’s recommendation to use deferred accounting to accommodate property tax increases.

Hearings are expected to start in May 2013 and a decision is expected in the third quarter of 2013.

PSCo – Colorado 2013 Steam Rate Case — In December 2012, PSCo filed a request to increase Colorado retail steam rates by $1.6 million in 2013 with subsequent step increases of $0.9 million in 2014 and $2.3 million in 2015. The request is based on a 2013 forecast test year, a 10.5 percent ROE, a rate base of $21 million for steam and an equity ratio of 56 percent. Final rates are expected to be effective in the third quarter of 2013.

Next steps in the procedural schedule are expected to be as follows:

●

Staff/Intervenor Direct Testimony – Aug. 7, 2013

●

Rebuttal Testimony and Reverse Cross-Answer Testimony – Aug. 28, 2013

●

Evidentiary Hearings – Sept. 23-27, 2013

●

Post-Hearing Statement Position – Oct. 11, 2013

●

Proposed Findings – prior to Dec. 31, 2013

PSCo – 2011 Electric Rate Case Earnings Test — On April 1, 2013, PSCo filed a tariff implementing the earnings sharing mechanism compliance with the settlement and CPUC decision for PSCo’s 2011 electric rate case. The earnings sharing mechanism is used to apply prospective electric rate adjustments for earnings in the prior year over PSCo’s authorized ROE threshold of 10 percent. Based on the filing, PSCo’s earnings did not exceed the established threshold. Any party disputing the calculation must file a notice with the CPUC identifying all issues by May 15, 2013.

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Electric, Purchased Gas and Resource Adjustment Clauses

Renewable Energy Credit (REC) Sharing — In May 2011, the CPUC determined that margin sharing on stand-alone REC transactions would be shared 20 percent to PSCo and 80 percent to customers beginning in 2011 and ultimately becoming 10 percent to PSCo and 90 percent to customers by 2014. The CPUC also approved a change to the treatment of hybrid REC trading margins (RECs that are bundled with energy) that allows the customers’ share of the margins to be netted against the renewable energy standard adjustment (RESA) regulatory asset balance.

In March 2012, the CPUC approved an annual margin sharing on the first $20 million of margins on hybrid REC trades of 80 percent to the customers and 20 percent to PSCo. Margins in excess of the $20 million are to be shared 90 percent to the customers and 10 percent to PSCo. The CPUC authorized PSCo to return to customers unspent carbon offset funds by crediting the RESA regulatory asset balance. For the three months ended March 31, 2013 and 2012, PSCo credited the RESA regulatory asset balance $4.0 million and $28.7 million, respectively. The cumulative credit to the RESA regulatory asset balance was $86.8 million and $82.8 million at March 31, 2013 and Dec. 31, 2012, respectively. The credits include the customers’ share of REC trading margins and the customers’ share of carbon offset funds.

This sharing mechanism will be effective through 2014 to provide the CPUC an opportunity to review the framework and evidence regarding actual deliveries.

SPS

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

Base Rate

SPS – Texas 2012 Electric Rate Case — In November 2012, SPS filed an electric rate case in Texas with the PUCT for an increase in annual revenue of approximately $90.2 million. The rate filing is based on a historic twelve month test year ended June 30, 2012 (adjusted for known and measurable changes), a requested ROE of 10.65 percent, an electric rate base of $1.15 billion and an equity ratio of 52 percent.

In April 2013, the parties filed a settlement agreement in which SPS’ base rate will increase by $37 million, effective May 1, 2013, on an interim basis pending the PUCT’s approval of the settlement, and by an additional $13.8 million on Sept. 1, 2013. In addition, the settlement allows SPS to file a transmission cost recovery adjustment rider in the fourth quarter of 2013 and for those rates to become effective on an interim basis in January 2014. Under the settlement, SPS cannot file another base rate case in 2013, but there are no restrictions on SPS filing a base rate case in 2014. The PUCT is expected to act on the settlement during the second quarter of 2013.

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

Base Rate

SPS – New Mexico 2012 Electric Rate Case — In December 2012, SPS filed an electric rate case in New Mexico with the NMPRC for an increase in annual revenue of approximately $45.9 million. The rate filing is based on a 2014 forecast test year, a requested ROE of 10.65 percent, a jurisdictional electric rate base of $479.8 million and an equity ratio of 53.89 percent.

In March 2013, the NMPRC ruled that SPS’ case, as originally filed, was incomplete due to confidential exhibits to testimony and schedules being included in SPS’ direct case, and directed the hearing examiner to review SPS’ claims of confidentiality and to determine the date the filing is complete. After SPS made filings to address the NMPRC’s concern about the confidential documents, the hearing examiner determined that SPS’ application was completed on April 12, 2013. The NMPRC has suspended the tariffs for an initial nine month period beyond that date, or until Jan. 11, 2014. The NMPRC has authority to suspend the rates for an additional three months beyond the initial nine month period, or until April 11, 2014.

Next steps in the procedural schedule are expected to be as follows:

●

Staff/Intervenor Direct Testimony – Aug. 8, 2013

●

Rebuttal Testimony – Aug. 29, 2013

●

Evidentiary Hearings – Sept. 16-27, 2013

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Purchase and Sale Agreement for Certain Texas Transmission Assets — On March 29, 2013, SPS entered into a purchase and sale agreement with Sharyland Distribution and Transmission Services, LLC for the sale of certain segments of SPS’ transmission lines and two related substations for a base purchase price of $37 million, subject to adjustments for unplanned capital expenditures. The transaction is subject to various regulatory approvals including that of the Federal Energy Regulatory Commission (FERC).

On April 29, 2013, SPS made filings regarding the planned transaction with the PUCT, the NMPRC and the FERC. If approved, the sale is expected to close by the end of 2013.

6.	Commitments and Contingencies

Except to the extent noted below and in Note 5, the circumstances set forth in Notes 12, 13 and 14 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2012, 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.

Purchased Power Agreements

Under certain purchased power agreements, NSP-Minnesota, PSCo and SPS purchase power from independent power producing entities for which the utility subsidiaries are required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. These specific purchased power agreements create a variable interest in the associated independent power producing entity.

Xcel Energy had approximately 3,324 megawatts (MW) of capacity under long-term purchased power agreements as of March 31, 2013 and Dec. 31, 2012, with entities that have been determined to be variable interest entities. 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. These agreements have expiration dates through the year 2033.

Guarantees and Indemnifications

Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities under specified agreements or transactions. The guarantees and bond indemnities issued by Xcel Energy Inc. guarantee payment or performance by its subsidiaries. As a result, Xcel Energy Inc.’s exposure under the guarantees and bond indemnities is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries limit the exposure to a maximum amount stated in the guarantees and bond indemnities. As of March 31, 2013 and Dec. 31, 2012, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.

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

(Millions of Dollars)	March 31, 2013		Dec. 31, 2012
Guarantees issued and outstanding	$	69.5	$	69.5
Current exposure under these guarantees		17.8		17.9
Bonds with indemnity protection		30.6		29.6

Indemnification Agreements

In connection with the acquisition of the 201 MW Nobles wind project in 2011, NSP-Minnesota agreed to indemnify the seller for losses arising out of a breach of certain representations and warranties. NSP-Minnesota’s indemnification obligation was capped at $20 million under the agreement. The indemnification obligation expired in March 2013.

Xcel Energy Inc. and its subsidiaries provide other indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. The maximum potential amount of future payments under these indemnifications cannot be reasonably estimated as the obligated amounts of these indemnifications often are not explicitly stated.

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Environmental Contingencies

Ashland Manufactured Gas Plant (MGP) Site — NSP-Wisconsin has been named a potentially responsible party (PRP) for contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (the Ashland site) includes property owned by NSP-Wisconsin, which was a site previously operated by a predecessor company as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park), on which an unaffiliated third party previously operated a sawmill and conducted creosote treating operations; and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments).

The U.S. Environmental Protection Agency (EPA) issued its Record of Decision (ROD) in 2010, which describes the preferred remedy the EPA has selected for the cleanup of the Ashland site. In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the site. The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intended to conduct or pay for the remediation at the Ashland site. As a result of those settlement negotiations, the EPA agreed to segment the Ashland site into separate areas. The first area (Phase I Project Area) includes soil and groundwater in Kreher Park and the Upper Bluff. The second area includes the Sediments.

In October 2012, a settlement among the EPA, the Wisconsin Department of Natural Resources (WDNR), the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin was approved by the U.S. District Court for the Western District of Wisconsin. This settlement resolves claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area. Under the terms of the settlement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area, but does not admit any liability with respect to the Ashland site. The settlement reflects a cost estimate for the clean up of the Phase I Project Area of $40 million. The settlement also resolves claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments. As part of the settlement, NSP-Wisconsin will convey approximately 1,390 acres of land to the State of Wisconsin. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues in 2013.

Negotiations between the EPA and NSP-Wisconsin regarding who will pay or perform the cleanup of the Sediments are ongoing. The EPA’s ROD for the Ashland site includes estimates that the cost of the preferred remediation related to the Sediments is between $63 million and $77 million, with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower.

In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site. Trial for this matter has been scheduled for June 2014.

At March 31, 2013 and Dec. 31, 2012, NSP-Wisconsin had recorded a liability of $103.8 million and $103.7 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $18.1 million and $20.1 million, respectively, was considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change. 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. Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, potential contributions by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.

NSP-Wisconsin has deferred the estimated site remediation costs, as a regulatory asset, based on an expectation that the Public Service Commission of Wisconsin (PSCW) will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized in NSP-Wisconsin rates recovery of all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by 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 retail rate case process. Under an existing PSCW policy, utilities have recovered remediation costs for MGPs in natural gas rates, amortized over a four- to six-year period. The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.

In a recent rate case decision, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site. In December 2012, the PSCW granted an exception to its existing policy at the request of NSP-Wisconsin. The elements of this exception include: 1) approval to begin recovery of estimated Phase 1 Project costs beginning on Jan. 1, 2013; 2) approval to amortize these estimated costs over a ten-year period; and 3) approval to apply a three percent carrying cost to the unamortized regulatory asset. Implementation of this exception will help mitigate the rate impact to natural gas customers and the risk to NSP-Wisconsin from a longer amortization period.

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Environmental Requirements

Cross-State Air Pollution Rule (CSAPR) — In 2011, the EPA issued the CSAPR to address long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO2) and nitrogen oxide (NOx) from utilities in the eastern half of the United States. For Xcel Energy, the rule would have applied in Minnesota, Wisconsin and Texas. The CSAPR would have set more stringent requirements than the proposed Clean Air Transport Rule and specifically would have required plants in Texas to reduce their SO2 and annual NOx emissions. The rule also would have created an emissions trading program.

In August 2012, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit also stated that the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement. In October 2012, the EPA, as well as state and local governments and environmental advocates, petitioned the D.C. Circuit to rehear the CSAPR appeal. In January 2013, the D.C. Circuit denied all requests for rehearing. In March 2013, the EPA and a coalition of environmental advocacy groups separately petitioned for U.S. Supreme Court review of the CSAPR decision. It is not known whether the Supreme Court will decide to review the D.C. Circuit’s decision.

As the EPA continues administering the CAIR while the CSAPR or a replacement rule is pending, Xcel Energy expects to comply with the CAIR as described below.

CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. The CAIR applies to Texas and Wisconsin. The CAIR does not apply to Minnesota.

Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. NSP-Wisconsin purchased allowances in 2012 and plans to continue to purchase allowances in 2013 to comply with the CAIR. In the SPS region, installation of low-NOx combustion control technology was completed in 2012 on Tolk Unit 1. SPS plans to install the same combustion control technology on Tolk Unit 2 in 2014. These installations will reduce or eliminate SPS’ need to purchase NOx emission allowances. In addition, SPS has sufficient SO2 allowances to comply with the CAIR in 2013. At March 31, 2013, the estimated annual CAIR NOx allowance cost for Xcel Energy did not have a material impact on the results of operations, financial position or cash flows.

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

PSCo

In 2011, the Colorado Air Quality Control Commission approved a BART state implementation plan (SIP) incorporating the Colorado CACJA emission reduction plan, which will satisfy regional haze requirements. The Colorado legislature enacted a statute approving the SIP (the Colorado SIP), which was signed into law in 2011. Subsequently, the Colorado Mining Association (CMA) challenged the Colorado SIP in a Colorado District Court. In June 2012, the CMA’s appeal was dismissed. The CMA appealed this decision, which is now pending in the Colorado Court of Appeals.

In September 2012, the EPA granted final approval of the Colorado SIP, including the CACJA emission reduction plan for PSCo, as satisfying BART requirements. The emission controls are expected to be installed between 2014 and 2017. Projected costs for emission controls at the Hayden and Pawnee plants are $340.9 million. PSCo expects the cost of any required capital investment will be recoverable from customers.

In March 2013, WildEarth Guardians petitioned the U.S. Court of Appeals for the 10th Circuit to review the EPA’s decision approving the Colorado SIP. WildEarth Guardians has stated that it will challenge the BART determination made for Comanche Units 1 and 2, which was a separate determination that was not part of the CACJA emission reduction plan. In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent, or that Selective Catalytic Reduction (SCR) be added to the units. PSCo has intervened in the case.

In 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. The following PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege that the Colorado BART rule is inadequate to satisfy the Clean Air Act (CAA) mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when the DOI will rule on the petition.

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NSP-Minnesota

In 2009, the Minnesota Pollution Control Agency (MPCA) approved the SIP for Minnesota (the Minnesota SIP), and submitted it to the EPA for approval. The MPCA selected the BART controls for Sherco Units 1 and 2 to improve visibility in the national parks. The MPCA concluded SCRs should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs. The MPCA’s source-specific BART controls for Sherco Units 1 and 2 consist of combustion controls for NOx and scrubber upgrades for SO2. The combustion controls have been installed on Sherco Units 1 and 2. The scrubber upgrades are underway and scheduled to be completed by January 2015.

The EPA’s preliminary review of the Minnesota SIP in 2011 indicated that SCR controls should be added to Sherco Units 1 and 2. Subsequently, the EPA and MPCA both determined that CSAPR meets BART requirements for purposes of the Minnesota SIP. In addition, the MPCA retained its source-specific BART determination for Sherco Units 1 and 2 from the 2009 Minnesota SIP. The EPA approved the Minnesota SIP for electric generating units (EGUs), and also approved the source-specific emission limits for Sherco Units 1 and 2 as strengthening the Minnesota SIP, but avoided characterizing them as BART limits.

In August 2012, the National Parks Conservation Association, Sierra Club, Voyageurs National Park Association, Friends of the Boundary Waters Wilderness, Minnesota Center for Environmental Advocacy and Fresh Energy appealed the EPA’s approval of the Minnesota SIP to the U.S. Court of Appeals for the Eighth Circuit. The Court denied intervention in the case to NSP-Minnesota and other regulated parties who petitioned to intervene. It is not yet known how the D.C. Circuit’s reversal of the CSAPR may impact the EPA’s approval of the Minnesota SIP.

The estimated cost for meeting the BART, regional haze and other CAA requirements is approximately $50 million, of which $32 million has already been spent on projects to reduce NOx emissions on Sherco Units 1 and 2. Xcel Energy anticipates that all costs associated with BART compliance will be fully recoverable through regulatory recovery mechanisms. If the above litigation results in further EPA proceedings concerning the Minnesota SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2.

In addition to the regional haze rules, there are other visibility rules related to a program called the Reasonably Attributable Visibility Impairment (RAVI) program. In 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 RAVI and, if so, whether the level of controls required by the MPCA is appropriate. The EPA plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program. It is not yet known when the EPA will publish a proposal under RAVI or what that proposal will entail. In December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club. The lawsuit alleges that the EPA has failed to perform a nondiscretionary duty to determine BART for the Sherco Units 1 and 2 under the RAVI program. The EPA filed an answer denying the allegations and asserting that it did not have a nondiscretionary duty under the RAVI program. NSP-Minnesota has requested the Court to allow it to intervene in this litigation. The Court has not yet ruled on NSP-Minnesota’s motion.

SPS

Harrington Units 1 and 2 are potentially subject to BART. Texas has developed a SIP (the Texas SIP) that finds the CAIR equal to BART for EGUs. As a result, no additional controls beyond CAIR compliance would be required. In May 2012, the EPA deferred its review of the Texas SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs. It is not yet known how the D.C. Circuit’s reversal of the CSAPR may impact the EPA’s approval of the Texas SIP.

Legal Contingencies

Xcel Energy is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

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Environmental Litigation

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in the U.S. District Court for the Northern District of California against Xcel Energy and 23 other utility, oil, gas and coal companies. Plaintiffs claim that defendants’ emission of carbon dioxide (CO2) and other greenhouse gases 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 (Ninth Circuit). In October 2012, the Ninth Circuit affirmed the U.S. District Court’s dismissal and subsequently rejected plaintiffs’ request for rehearing. Plaintiffs subsequently filed a petition for review with the United States Supreme Court. It is unknown whether the United States Supreme Court will grant this petition. 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. Although Xcel Energy believes the likelihood of loss is remote based primarily on existing case law, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. No accrual has been recorded for this matter.

Comer vs. Xcel Energy Inc. et al. — In May 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in the U.S. District Court in Mississippi. The complaint alleges defendants’ CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property. Plaintiffs base their claims on public and private nuisance, trespass and negligence. Among the defendants named in the complaint are Xcel Energy Inc., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota. The amount of damages claimed by plaintiffs is unknown. The defendants believe this lawsuit is without merit and filed a motion to dismiss the lawsuit. In March 2012, the U.S. District Court granted this motion for dismissal. In April 2012, plaintiffs appealed this decision to the U.S. Court of Appeals for the Fifth Circuit. Oral arguments occurred in May 2013. It is uncertain when the Fifth Circuit will issue its decision. Although Xcel Energy believes the likelihood of loss is remote based primarily on existing case law, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. No accrual has been recorded for this matter.

Employment, Tort and Commercial Litigation

Merricourt Wind Project Litigation — In April 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota. NSP-Minnesota’s decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact. NSP-Minnesota also terminated the agreements due to enXco’s nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011. NSP-Minnesota recorded a $101 million deposit in the first quarter of 2011, which was collected in April 2011. In May 2011, NSP-Minnesota filed a declaratory judgment action in the U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements. enXco also filed a separate lawsuit in the same court seeking approximately $240 million for an alleged breach of contract. NSP-Minnesota believes enXco’s lawsuit is without merit. On Oct. 22, 2012, NSP-Minnesota filed a motion for summary judgment. In April 2013, the U.S. District Court granted NSP-Minnesota’s motion and entered judgment in its favor. On April 23, 2013 enXco filed a notice of appeal to the Eighth Circuit. It is uncertain when the Eighth Circuit will decide this appeal. Although Xcel Energy believes the likelihood of loss is remote based on existing case law and the U.S. District Court’s April 2013 decision, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. No accrual has been recorded for this matter.

Exelon Wind (formerly John Deere Wind (JD Wind)) Complaint — Several lawsuits in Texas state and federal courts and regulatory proceedings have arisen out of a dispute concerning SPS’ payments for energy produced from the Exelon Wind subsidiaries’ projects. There are two main areas of dispute. First, Exelon Wind claims that it established legally enforceable obligations (LEOs) for each of its 12 wind facilities in 2005 through 2008 that require SPS to buy power based on SPS’ forecasted avoided cost as determined in 2005 through 2008. Although SPS has refused to accept Exelon Wind’s LEOs, SPS accepts that it must take energy from Exelon Wind under SPS’ PUCT Qualifying Facilities (QF) Tariff. Second, Exelon Wind has raised various challenges to SPS’ PUCT QF Tariff, which became effective in August 2010. The state and federal lawsuits are in various stages of litigation. SPS believes the likelihood of loss in these lawsuits is remote based primarily on existing case law and while it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome, SPS believes such loss would not be material based upon its belief that it would be permitted to recover such costs, if needed, through its various fuel clause mechanisms. No accrual has been recorded for this matter.

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Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there were unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for December 2000 through June 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling, the FERC has allowed the parties to request additional evidence. Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million. In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings. Certain purchasers filed appeals of the FERC’s orders in this proceeding with the Ninth Circuit.

In an order issued in August 2007, the Ninth Circuit remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges in the California organized markets. The Ninth Circuit denied a petition for rehearing in April 2009, and the mandate was issued.

The FERC has issued an order on remand establishing principles for the review proceeding in October 2011. In September 2012, the City of Seattle filed its direct case against PSCo and other Pacific Northwest sellers claiming refunds for the period January 2000 through June 2001. Seattle indicated that for the period June 2000 through June 2001 PSCo had sales to the City of Seattle of approximately $50 million. The City of Seattle did not identify specific instances of unlawful market activity by PSCo, but rather based its claim for refunds on market dysfunction in the Western markets. PSCo submitted its answering case in December 2012.

On April 5, 2013, the FERC issued an order on rehearing of its remand order issued for the October 2011 review proceedings. The FERC confirmed that the City of Seattle would be able to attempt to obtain refunds back from January 2000, but reaffirmed the transaction-specific standard that the City of Seattle and other complainants would have to comply with to meet to obtain refunds. In addition, the FERC rejected the imposition of any market-wide remedies. Although the FERC order on rehearing established the period for which the City of Seattle could seek refunds as January 2000 through June 2001, it is unclear whether Seattle has a claim against PSCo prior to June 2000.

Preliminary calculations of the City of Seattle’s claim for refunds from PSCo are approximately $28 million not including interest. PSCo has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, PSCo is currently unable to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. In making this assessment, PSCo considered two factors. First, not withstanding PSCo’s view that the City of Seattle has failed to apply the standard that the FERC has established in this proceeding, and the recognition that this case raises a novel issue and the FERC’s standard will likely be challenged on appeal to the Ninth Circuit, the outcome of such an appeal cannot be predicted with any certainty. Second, PSCo would expect to make equitable arguments against refunds even if the City of Seattle were to establish that it was overcharged for transactions. If a loss were sustained, PSCo would attempt to recover those losses from other PRPs. No accrual has been recorded for this matter.

Nuclear Power Operations and Waste Disposal

Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the U.S. Department of Energy’s (DOE) failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the United States and NSP-Minnesota. NSP-Minnesota sought contract damages in this lawsuit through Dec. 31, 2004. In September 2007, the court awarded NSP-Minnesota $116.5 million in damages. In August 2007, NSP-Minnesota filed a second complaint; this lawsuit claimed damages for the period Jan. 1, 2005 through Dec. 31, 2008.

In July 2011, the United States and NSP-Minnesota executed a settlement agreement resolving both lawsuits, providing an initial $100 million payment from the United States to NSP-Minnesota, and providing a method by which NSP-Minnesota can recover its spent fuel storage costs through 2013, estimated to be an additional $100 million. The settlement does not address costs for used fuel storage after 2013; such costs could be the subject of future litigation. NSP-Minnesota received the initial $100 million payment in August 2011, the second installment of $18.6 million in March 2012, and the third installment of $20.7 million in October 2012. Amounts were subsequently credited to customers, except for approved reductions such as legal costs, customer credit amounts still in process at March 31, 2013, and amounts set aside to be credited through another regulatory mechanism.

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In NSP-Wisconsin’s 2012 Electric and Gas Rate Case, the PSCW authorized NSP-Wisconsin to utilize the proceeds from the second and third installments to be included as a reduction of the 2013 electric rate increase. In December 2012, the MPUC approved NSP-Minnesota’s triennial nuclear decommissioning filing which required NSP-Minnesota to place the Minnesota retail portion of the DOE settlement payments for the third installment of $15.3 million and the anticipated fourth installment in 2013 into the nuclear decommissioning fund when received. NSP-Minnesota proposed to contribute the second, third and fourth installments to the nuclear decommissioning fund to offset the increase in the decommissioning accrual that was included in the 2012 North Dakota electric rate case. That filing is pending NDPSC action.

7.	Borrowings and Other Financing Instruments

Short-Term Borrowings

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. NSP-Wisconsin does not participate in the money pool. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. The money pool balances are eliminated in consolidation.

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	2,450		$	2,450
Amount outstanding at period end		425			602
Average amount outstanding		813			403
Maximum amount outstanding		1,160			634
Weighted average interest rate, computed on a daily basis		0.35	%		0.35	%
Weighted average interest rate at period end		0.33			0.36

Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At March 31, 2013 and Dec. 31, 2012, there were $15.2 million and $14.2 million of letters of credit outstanding, respectively, under the credit facilities. All letters of credit outstanding were issued under the credit facilities at March 31, 2013 and Dec. 31, 2012. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

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

At March 31, 2013, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available:

(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available
Xcel Energy Inc.	$	800.0	$	343.0	$	457.0
PSCo		700.0		4.0		696.0
NSP-Minnesota		500.0		56.2		443.8
SPS		300.0		16.0		284.0
NSP-Wisconsin		150.0		21.0		129.0
Total	$	2,450.0	$	440.2	$	2,009.8

(a)	These credit facilities expire in July 2017.

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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding at March 31, 2013 and Dec. 31, 2012.

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Long-Term Borrowings and Other Financing Instruments

In March 2013, PSCo issued $250 million of 2.50 percent first mortgage bonds due March 15, 2023 and $250 million of 3.95 percent first mortgage bonds due March 15, 2043.

Issuances of Common Stock — In March 2013, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $400 million of its common stock through an at-the-market offering program. As of March 31, 2013, Xcel Energy Inc. had issued 5.5 million shares of common stock through this program and received cash proceeds of $158.6 million, net of $1.6 million in fees and commissions.

Xcel Energy Inc. had commitments not recognized on the consolidated balance sheet at March 31, 2013 to sell 2.2 million shares of common stock under sales transactions entered into during the last three trading days of March 2013. Subsequent to March 31, 2013, Xcel Energy Inc. issued shares to settle these transactions in exchange for net cash proceeds of $64.5 million. The proceeds from the issuances of common stock were used to repay short-term debt, infuse equity into the utility subsidiaries and for other general corporate purposes.

Planned Debt Redemption — On April 15, 2013, Xcel Energy Inc. notified the trustee of its intent to redeem the entire $400 million principal amount of the 7.60 percent junior subordinated notes on May 31, 2013.

8.	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical 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 — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, international equity funds, private equity investments and real estate investments 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 with proper notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Based on Xcel Energy’s evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3.

Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities, except for asset-backed and mortgage-backed securities, for which the third party service also utilizes additional inputs in a discounted cash flow model, including forecasted prepayments and risk adjusted discounting.

Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

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Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

Electric commodity derivatives held by NSP-Minnesota include financial transmission rights (FTRs) purchased from Midwest Independent Transmission System Operator, Inc. (MISO). FTRs purchased from MISO are financial instruments that entitle or obligate the holder to one year of monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. NSP-Minnesota’s valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model – including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Monthly FTR settlements are included in the fuel clause adjustment, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of NSP-Minnesota’s FTRs relative to its electric utility operations, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy.

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. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. The MPUC approved NSP-Minnesota’s proposed change in escrow fund investment strategy in September 2012. The MPUC approved an asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.

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

Unrealized gains for the nuclear decommissioning fund were $171.3 million and $135.8 million at March 31, 2013 and Dec. 31, 2012, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $49.6 million and $46.4 million at March 31, 2013 and Dec. 31, 2012, respectively.

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The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at March 31, 2013 and Dec. 31, 2012:

	March 31, 2013
			Fair Value

(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	94,131	$	88,759	$	5,372	$	-	$	94,131
Commingled funds		422,333		-		442,976		-		442,976
International equity funds		67,032		-		70,587		-		70,587
Private equity investments		29,199		-		-		34,506		34,506
Real estate		33,048		-		-		40,406		40,406
Debt securities:
Government securities		16,375		-		16,464		-		16,464
U.S. corporate bonds		210,505		-		216,318		-		216,318
International corporate bonds		18,562		-		19,226		-		19,226
Municipal bonds		103,090		-		103,837		-		103,837
Asset-backed securities		1,636		-		1,636		-		1,636
Mortgage-backed securities		4,627		-		5,106		-		5,106
Equity securities:
Common stock		411,751		488,811		-		-		488,811
Total	$	1,412,289	$	577,570	$	881,522	$	74,912	$	1,534,004

(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $89.8 million of equity investments in unconsolidated subsidiaries and $39.9 million of miscellaneous investments.

	Dec. 31, 2012
			Fair Value

(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	246,904	$	237,938	$	8,966	$	-	$	246,904
Commingled funds		396,681		-		417,583		-		417,583
International equity funds		66,452		-		69,481		-		69,481
Private equity investments		27,943		-		-		33,250		33,250
Real estate		32,561		-		-		39,074		39,074
Debt securities:
Government securities		21,092		-		21,521		-		21,521
U.S. corporate bonds		162,053		-		169,488		-		169,488
International corporate bonds		15,165		-		16,052		-		16,052
Municipal bonds		21,392		-		23,650		-		23,650
Asset-backed securities		2,066		-		-		2,067		2,067
Mortgage-backed securities		28,743		-		-		30,209		30,209
Equity securities:
Common stock		379,093		420,263		-		-		420,263
Total	$	1,400,145	$	658,201	$	726,741	$	104,600	$	1,489,542

(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $91.2 million of equity investments in unconsolidated subsidiaries and $37.1 million of miscellaneous investments.

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The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three months ended March 31, 2013 and 2012:

								Gains
								Recognized as
								Regulatory		Transfers Out
(Thousands of Dollars)	Jan. 1, 2013		Purchases		Settlements			Liabilities		of Level 3 (a)			March 31, 2013
Private equity investments	$	33,250	$	1,256		-			-	$	-		$	34,506
Real estate		39,074		4,786		(4,299	)		845		-			40,406
Asset-backed securities		2,067		-		-			-		(2,067	)		-
Mortgage-backed securities		30,209		-		-			-		(30,209	)		-
Total	$	104,600	$	6,042	$	(4,299	)	$	845	$	(32,276	)	$	74,912

(a)	Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements.

								Gains (Losses)
								Recognized as
								Regulatory Assets			Transfers Out
(Thousands of Dollars)	Jan. 1, 2012		Purchases		Settlements			and Liabilities			of Level 3		March 31, 2012
Private equity investments	$	9,203	$	10,155	$	-		$	710		$	-	$	20,068
Real estate		26,395		1,636		(1,766	)		1,640			-		27,905
Asset-backed securities		16,501		-		(1	)		47			-		16,547
Mortgage-backed securities		78,664		6,904		(16,728	)		(169	)		-		68,671
Total	$	130,763	$	18,695	$	(18,495	)	$	2,228		$	-	$	133,191

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at March 31, 2013:

	Final Contractual Maturity
	Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years
(Thousands of Dollars)	Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Government securities	$	-	$	2,498	$	10,165	$	3,801	$	16,464
U.S. corporate bonds		1,441		40,952		92,076		81,849		216,318
International corporate bonds		-		4,300		13,746		1,180		19,226
Municipal bonds		829		16,628		21,917		64,463		103,837
Asset-backed securities		-		1,636		-		-		1,636
Mortgage-backed securities		-		-		-		5,106		5,106
Debt securities	$	2,270	$	66,014	$	137,904	$	156,399	$	362,587

Derivative Instruments Fair Value Measurements

Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.

Interest Rate Derivatives — Xcel Energy enters 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, 2013, accumulated other comprehensive losses related to interest rate derivatives included $2.4 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for any unsettled hedges.

Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct various 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.

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Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its 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, natural gas for resale and vehicle fuel.

At March 31, 2013, Xcel Energy had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. Xcel Energy also enters 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 other comprehensive income 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, 2013 and 2012.

At March 31, 2013, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, Xcel Energy enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, 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, 2013 and Dec. 31, 2012:

(Amounts in Thousands) (a)(b)	March 31, 2013		Dec. 31, 2012
Megawatt hours (MWh) of electricity		31,536		55,976
Million British thermal units (MMBtu) of natural gas		31		725
Gallons of vehicle fuel		632		682

(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.

Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, 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 derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.

Xcel Energy Inc. and its subsidiaries employ additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and 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.

Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities. At March 31, 2013, four of Xcel Energy’s 10 most significant counterparties for these activities, comprising $61.4 million or 20 percent of this credit exposure at March 31, 2013, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Five of the 10 most significant counterparties, comprising $80.6 million or 27 percent of this credit exposure at March 31, 2013, were not rated by these agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $7.5 million or 3 percent of this credit exposure at March 31, 2013, had credit quality less than investment grade, based on Xcel Energy’s internal analysis. All 10 of these significant counterparties are municipal or cooperative electric entities or other utilities, and no single counterparty comprised greater than 10 percent of Xcel Energy’s credit exposure at March 31, 2013.

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

	Three Months Ended March 31
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(61,241	)	$	(45,738	)
After-tax net unrealized gains related to derivatives accounted for as hedges		13			25,392
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(305	)		181
Accumulated other comprehensive loss related to cash flow hedges at March 31	$	(61,533	)	$	(20,165	)

The following tables detail the impact of derivative activity during the three months ended March 31, 2013 and 2012, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

	Three Months Ended March 31, 2013
	Pre-Tax Fair Value				Pre-Tax (Gains) Losses
	Gains (Losses) Recognized				Reclassified into Income
	During the Period in:				During the Period from:
	Accumulated				Accumulated						Pre-Tax Gains
	Other		Regulatory		Other			Regulatory			Recognized
	Comprehensive		(Assets) and		Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Loss		Liabilities		Loss			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	-	$	-	$	1,150	(a)	$	-		$	-
Vehicle fuel and other commodity		25		-		(26	)(e)		-			-
Total	$	25	$	-	$	1,124		$	-		$	-

Other derivative instruments
Commodity trading	$	-	$	-	$	-		$	-		$	2,776	(b)
Electric commodity		-		6,419		-			(15,229	)(c)		-
Natural gas commodity		-		54		-			9	(d)		16	(c)
Total	$	-	$	6,473	$	-		$	(15,220	)	$	2,792

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Three Months Ended March 31, 2012

Pre-Tax Fair Value