Edgar Filing: XCEL ENERGY INC

(Amounts in Thousands) ^(a)(b)

March 31, 2016

Dec. 31, 2015

Megawatt hours of electricity

Million British thermal units of natural gas

Gallons of vehicle fuel

SEC Document

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, 2016



¨	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. x Yes ¨ No

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). x Yes ¨ No

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 ¨		Smaller reporting company ¨
(Do not check if 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 x No

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 May 4, 2016
Common Stock, $2.50 par value		507,952,795 shares

TABLE OF CONTENTS



PART I	FINANCIAL INFORMATION
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	33
Item 3 —	Quantitative and Qualitative Disclosures about Market Risk	50
Item 4 —	Controls and Procedures	51

PART II	OTHER INFORMATION
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	53

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. The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin, which is operated on an integrated basis and is managed by NSP-Minnesota, is referred to collectively as the NSP System. 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
	2016			2015
Operating revenues
Electric	$	2,185,119		$	2,224,863
Natural gas	565,689			715,996
Other	21,465			21,360
Total operating revenues	2,772,273			2,962,219

Operating expenses
Electric fuel and purchased power	861,852			950,132
Cost of natural gas sold and transported	312,117			472,371
Cost of sales — other	8,245			10,049
Operating and maintenance expenses	577,410			585,830
Conservation and demand side management program expenses	57,436			53,805
Depreciation and amortization	320,020			273,098
Taxes (other than income taxes)	145,323			136,626
Loss on Monticello life cycle management/extended power uprate project	—			129,463
Total operating expenses	2,282,403			2,611,374

Operating income	489,870			350,845

Other income, net	4,250			3,161
Equity earnings of unconsolidated subsidiaries	13,182			7,776
Allowance for funds used during construction — equity	13,113			12,660

Interest charges and financing costs
Interest charges — includes other financing costs of $6,336 and $5,698, respectively	156,443			144,940
Allowance for funds used during construction — debt	(5,990		)	(6,144		)
Total interest charges and financing costs	150,453			138,796

Income before income taxes	369,962			235,646
Income taxes	128,650			83,580
Net income	$	241,312		$	152,066

Weighted average common shares outstanding:
Basic	508,667			506,983
Diluted	509,150			507,393

Earnings per average common share:
Basic	$	0.47		$	0.30
Diluted	0.47			0.30

Cash dividends declared per common share	$	0.34		$	0.32

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
	2016			2015
Net income	$	241,312		$	152,066

Other comprehensive income

Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $142 and $569, respectively	211			876

Derivative instruments:
Net fair value decrease, net of tax of $(2) and $(7), respectively	(4		)	(11		)
Reclassification of losses to net income, net of tax of $604 and $382, respectively	938			585
	934			574
Marketable securities:
Net fair value increase, net of tax of $0 and $0, respectively	—			1

Other comprehensive income	1,145			1,451
Comprehensive income	$	242,457		$	153,517

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
	2016			2015
Operating activities
Net income	$	241,312		$	152,066
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	323,761			277,388
Conservation and demand side management program amortization	1,162			1,451
Nuclear fuel amortization	25,750			28,465
Deferred income taxes	160,379			82,773
Amortization of investment tax credits	(1,307		)	(1,384		)
Allowance for equity funds used during construction	(13,113		)	(12,660		)
Equity earnings of unconsolidated subsidiaries	(13,182		)	(7,776		)
Dividends from unconsolidated subsidiaries	11,481			9,876
Share-based compensation expense	13,099			10,225
Loss on Monticello life cycle management/extended power uprate project	—			129,463
Net realized and unrealized hedging and derivative transactions	5,576			12,778
Other	(388		)	—
Changes in operating assets and liabilities:
Accounts receivable	(4,780		)	(291		)
Accrued unbilled revenues	129,444			183,974
Inventories	88,570			92,010
Other current assets	(16,635		)	56,685
Accounts payable	(22,063		)	(99,029		)
Net regulatory assets and liabilities	34,404			146,097
Other current liabilities	(44,929		)	34,642
Pension and other employee benefit obligations	(118,774		)	(85,469		)
Change in other noncurrent assets	(1,196		)	(5		)
Change in other noncurrent liabilities	(8,508		)	(25,885		)
Net cash provided by operating activities	790,063			985,394

Investing activities
Utility capital/construction expenditures	(700,319		)	(770,609		)
Proceeds from insurance recoveries	—			24,241
Allowance for equity funds used during construction	13,113			12,660
Purchases of investments in external decommissioning fund	(109,373		)	(387,826		)
Proceeds from the sale of investments in external decommissioning fund	104,280			386,111
Investments in WYCO Development LLC and other	(260		)	(321		)
Other, net	(1,548		)	(2,645		)
Net cash used in investing activities	(694,107		)	(738,389		)

Financing activities
Repayments of short-term borrowings, net	(663,000		)	(50,500		)
Proceeds from issuance of long-term debt	747,127			—
Repayments of long-term debt	(333		)	(455		)
Proceeds from issuance of common stock	—			1,411
Purchase of common stock for settlement of equity awards	(789		)	—
Dividends paid	(162,410		)	(144,025		)
Net cash used in financing activities	(79,405		)	(193,569		)

Net change in cash and cash equivalents	16,551			53,436
Cash and cash equivalents at beginning of period	84,940			79,608
Cash and cash equivalents at end of period	$	101,491		$	133,044

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(164,511	)	$	(161,717	)
Cash received for income taxes, net	7,414			62,697

Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable	$	192,818		$	239,905
Issuance of common stock for reinvested dividends and 401(k) plans	7,703			14,433

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, 2016			Dec. 31, 2015
Assets
Current assets
Cash and cash equivalents	$	101,491		$	84,940
Accounts receivable, net	729,386			724,606
Accrued unbilled revenues	525,423			654,867
Inventories	520,054			608,584
Regulatory assets	317,489			344,630
Derivative instruments	23,293			33,842
Deferred income taxes	180,513			140,219
Prepaid taxes	180,825			163,023
Prepayments and other	154,143			155,734
Total current assets	2,732,617			2,910,445

Property, plant and equipment, net	31,433,406			31,205,851

Other assets
Nuclear decommissioning fund and other investments	1,917,709			1,902,995
Regulatory assets	2,897,502			2,858,741
Derivative instruments	55,612			51,083
Other	32,998			32,581
Total other assets	4,903,821			4,845,400
Total assets	$	39,069,844		$	38,961,696

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	656,516		$	657,021
Short-term debt	183,000			846,000
Accounts payable	809,656			960,982
Regulatory liabilities	272,647			306,830
Taxes accrued	525,934			438,189
Accrued interest	148,112			166,829
Dividends payable	172,704			162,410
Derivative instruments	27,553			29,839
Other	392,446			490,197
Total current liabilities	3,188,568			4,058,297

Deferred credits and other liabilities
Deferred income taxes	6,493,644			6,293,661
Deferred investment tax credits	67,112			68,419
Regulatory liabilities	1,373,140			1,332,889
Asset retirement obligations	2,639,628			2,608,562
Derivative instruments	167,299			168,311
Customer advances	221,683			228,999
Pension and employee benefit obligations	812,998			941,002
Other	285,743			261,756
Total deferred credits and other liabilities	12,061,247			11,903,599

Commitments and contingencies
Capitalization
Long-term debt	13,148,395			12,398,880
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,952,795 and 507,535,523 shares outstanding at March 31, 2016 and Dec. 31, 2015, respectively	1,269,882			1,268,839
Additional paid in capital	5,889,939			5,889,106
Retained earnings	3,620,421			3,552,728
Accumulated other comprehensive loss	(108,608		)	(109,753		)
Total common stockholders’ equity	10,671,634			10,600,920
Total liabilities and equity	$	39,069,844		$	38,961,696

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						Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Stockholders’ Equity
	Shares	Par Value		Additional Paid In Capital			Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Stockholders’ Equity
Three Months Ended March 31, 2016 and 2015
Balance at Dec. 31, 2014	505,733	$	1,264,333	$	5,837,330		$	3,220,958		$	(108,139	)	$	10,214,482
Net income							152,066						152,066
Other comprehensive income										1,451			1,451
Dividends declared on common stock							(163,120		)				(163,120		)
Issuances of common stock	931	2,326		893									3,219
Share-based compensation				6,772									6,772
Balance at March 31, 2015	506,664	$	1,266,659	$	5,844,995		$	3,209,904		$	(106,688	)	$	10,214,870

Balance at Dec. 31, 2015	507,536	$	1,268,839	$	5,889,106		$	3,552,728		$	(109,753	)	$	10,600,920
Net income							241,312						241,312
Other comprehensive income										1,145			1,145
Dividends declared on common stock							(173,619		)				(173,619		)
Issuances of common stock	417	1,043		(3,755		)							(2,712		)
Purchase of common stock for settlement of equity awards				(789		)							(789		)
Share-based compensation				5,377									5,377
Balance at March 31, 2016	507,953	$	1,269,882	$	5,889,939		$	3,620,421		$	(108,608	)	$	10,671,634

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, 2016 and Dec. 31, 2015; 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, 2016 and 2015; and its cash flows for the three months ended March 31, 2016 and 2015. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2016 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, 2015 balance sheet information has been derived from the audited 2015 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2015. 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, 2015, filed with the SEC on Feb. 19, 2016. 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, 2015, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2.	Accounting Pronouncements

Recently Issued

Revenue Recognition — In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. The guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. Xcel Energy is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No 2015-17), which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Other than the prescribed classification of all deferred tax assets and liabilities as noncurrent, Xcel Energy does not expect the implementation of ASU 2015-17 to have a material impact on its consolidated financial statements.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which among other changes in accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. Xcel Energy is currently evaluating the impact of adopting ASU 2016-01 on its consolidated financial statements.

Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which, for lessees, requires balance sheet recognition of right-of-use assets and lease liabilities for all leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018, and early adoption is permitted. Xcel Energy is currently evaluating the impact of adopting ASU 2016-02 on its consolidated financial statements.

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Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU 2016-09), which amends existing guidance to simplify several aspects of accounting and presentation for share-based payment transactions, including the accounting for income taxes and forfeitures, as well as presentation in the statement of cash flows. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Xcel Energy is currently evaluating the impact of adopting ASU 2016-09 on its consolidated financial statements.

Recently Adopted

Consolidation — In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. Xcel Energy implemented the guidance on Jan. 1, 2016, and other than the classification of certain real estate investments held within the Nuclear Decommissioning Trust as non-consolidated variable interest entities, the implementation did not have a significant impact on its consolidated financial statements.

Presentation of Debt Issuance Costs — In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. Xcel Energy implemented the new guidance as required on Jan. 1, 2016, and as a result, $94.5 million of deferred debt issuance costs are presented as a deduction from the carrying amount of long-term debt on the consolidated balance sheet as of March 31, 2016, and $91.8 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015.

Fair Value Measurement — In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which eliminates the requirement to categorize fair value measurements using a net asset value (NAV) methodology in the fair value hierarchy. Xcel Energy implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its consolidated financial statements. For related disclosures, see Note 8 to the consolidated financial statements.


3.	Selected Balance Sheet Data



(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	778,953		$	776,494
Less allowance for bad debts	(49,567		)	(51,888		)
	$	729,386		$	724,606



(Thousands of Dollars)	March 31, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	298,345	$	290,690
Fuel	172,098		202,271
Natural gas	49,611		115,623
	$	520,054	$	608,584

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(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	36,604,585		$	36,464,050
Natural gas plant	5,017,324			4,944,757
Common and other property	1,720,351			1,709,508
Plant to be retired ^(a)	34,606			38,249
Construction work in progress	1,486,070			1,256,949
Total property, plant and equipment	44,862,936			44,413,513
Less accumulated depreciation	(13,790,489		)	(13,591,259		)
Nuclear fuel	2,450,363			2,447,251
Less accumulated amortization	(2,089,404		)	(2,063,654		)
	$	31,433,406		$	31,205,851


^(a)	In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC). Amounts are presented net of accumulated depreciation.


4.	Income Taxes

Except to the extent noted below, 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, 2015 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Tax Loss Carryback Claims — In 2012, 2013, 2014 and 2015, Xcel Energy identified certain expenses related to 2009, 2010, 2011, 2013, 2014 and 2015 that qualify for an extended carryback beyond the typical two-year carryback period. As a result of a higher tax rate in prior years, Xcel Energy recognized a tax benefit of approximately $5 million in 2015, $17 million in 2014 and $12 million in 2013 and $15 million in 2012.

Federal Audit — Xcel Energy files a consolidated federal income tax return. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of March 31, 2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 and 2013 claims, the recently filed 2014 claim, and the anticipated claim for 2015. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals); however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the Appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of March 31, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

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, 2016, 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		2009
Minnesota		2009
Texas		2009
Wisconsin		2011

In February 2016, the state of Texas began an audit of years 2009 and 2010. As of March 31, 2016, the state of Texas had not proposed any adjustments, and there were 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.

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A reconciliation of the amount of unrecognized tax benefit is as follows:



(Millions of Dollars)	March 31, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	26.3	$	25.8
Unrecognized tax benefit — Temporary tax positions	96.2		94.9
Total unrecognized tax benefit	$	122.5	$	120.7

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, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(38.5	)	$	(36.7	)

It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals and audit progress, the Texas audit progresses and other state audits resume. As the IRS Appeals, IRS audit, and Texas audit progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $58 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, 2016 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2016 or Dec. 31, 2015.


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, 2015, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)

NSP-Minnesota – Minnesota 2016 Multi-Year Electric Rate Case — In November 2015, NSP-Minnesota filed a three-year electric rate case with the MPUC. The rate case is based on a requested return on equity (ROE) of 10.0 percent and a 52.50 percent equity ratio. The request is detailed in the table below:



Request (Millions of Dollars)	2016			2017			2018
Rate request	$	194.6		$	52.1		$	50.4
Increase percentage	6.4		%	1.7		%	1.7		%
Interim request	$	163.7		$	44.9		N/A
Rate base	$	7,800		$	7,700		$	7,700

NSP-Minnesota also proposed a five-year alternative plan that would extend the rate plan two additional years. In addition, NSP-Minnesota has requested the MPUC encourage parties to engage in a formal mediation type procedure as outlined by Minnesota’s rate case statute which may streamline the settlement process.

In December 2015, the MPUC approved interim rates for 2016. The MPUC deferred making a decision on incremental interim rates for 2017 and indicated that NSP-Minnesota could bring back its request in the fourth quarter of 2016.

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The major components of the requested rate increase are summarized below:



(Millions of Dollars)	2016			2017			2018			Total
2014 multi-year rate case items:
Excess depreciation reserve	$	26.0		$	51.0		$	—		$	77.0
Department of Energy (DOE) settlement	25.7			—			—			25.7
Monticello life cycle management (LCM)/extended power uprate (EPU)	11.2			(1.6		)	(1.5		)	8.1
	62.9			49.4			(1.5		)	110.8
Additional items:
Capital investments	128.7			12.8			44.6			186.1
Property taxes	30.2			7.6			5.2			43.0
NOL carryforwards	(6.3		)	(24.5		)	(6.5		)	(37.3		)
Other costs	(20.9		)	6.8			8.6			(5.5		)
	131.7			2.7			51.9			186.3

Total rate request	$	194.6		$	52.1		$	50.4		$	297.1

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


•	Intervenors’ direct testimony — June 14, 2016;


•	Rebuttal testimony — Aug. 9, 2016;


•	Surrebuttal testimony — Sept. 16, 2016;


•	Settlement conference — Sept. 26, 2016;


•	Evidentiary hearing — Oct. 4-7, 2016;


•	Administrative Law Judge (ALJ) report — Feb. 21, 2017; and


•	MPUC order — June 1, 2017.

NSP-Minnesota – 2016 Transmission Cost Recovery (TCR) Filing — In October 2015, NSP-Minnesota submitted its 2016 TCR filing with the MPUC, requesting recovery of $19.2 million of 2016 transmission investment costs not included in electric base rates. This filing included an option to keep approximately $59.1 million of revenue requirements associated with two CapX2020 projects completed in 2015 within the TCR rider or to include these revenue requirements in electric base rates during the interim rate implementation of the next electric rate case. In November 2015, NSP-Minnesota submitted an update to its TCR filing in which it confirmed that it was requesting the MPUC approve keeping the two CapX2020 projects in the TCR rider, increasing the revenue requirements to $78.3 million, until the conclusion of the 2016 Minnesota electric rate case.

In April 2016, NSP-Minnesota received comments from the Minnesota Department of Commerce (DOC) requesting additional support for the costs incurred for the CapX2020 La Crosse-Madison project and the CapX2020 Big Stone-Brookings project, as well as the updated financial impact for the actual non-prorated accumulated deferred income tax (ADIT) as opposed to the forecasted prorated ADIT used in the cost recovery calculations. An MPUC decision is expected later in 2016.

NSP-Minnesota – Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello LCM/EPU project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 megawatts (MW) in 2015. The Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes allowance for funds used during construction (AFUDC). In 2008, project expenditures were initially estimated at approximately $320 million, excluding AFUDC.

In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent. In March 2015, the MPUC voted to allow for full recovery, including a return, on approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used-and-useful for 2014. As a result of these determinations, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015, after which the remaining book value of the Monticello project represented the present value of the estimated future cash flows.

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NSP-Wisconsin

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

Wisconsin 2017 Electric and Gas Rate Case — On April 1, 2016, NSP-Wisconsin filed a request with the PSCW for an increase in annual electric rates of $17.4 million, or 2.4 percent, and an increase in natural gas rates by $4.8 million, or 3.9 percent, effective January 2017.

The electric rate request is for the limited purpose of recovering increases in (i) generation and transmission fixed charges and fuel and purchased power expenses related to the interchange agreement with NSP-Minnesota, and (ii) costs associated with forecasted average rate base of $1.188 billion in 2017.

The natural gas rate request is for the limited purpose of recovering expenses related to the ongoing environmental remediation of a former manufactured gas plant site and adjacent area in Ashland, Wis.

No changes are being requested to the capital structure or the 10.0 percent ROE authorized by the PSCW in the 2016 rate case. As part of an agreement with stakeholders to limit the size and scope of the case, NSP-Wisconsin also agreed to an earnings cap, solely for 2017, in which 100 percent of the earnings in excess of the authorized ROE would be refunded to customers.

The major components of the requested rate increases are summarized below:



Electric Rate Request (Millions of Dollars)	Request
Rate base investments	$	11.0
Generation and transmission expenses (excluding fuel and purchased power) ^(a)	6.8
Fuel and purchased power expenses	11.0
Subtotal	28.8
2015 fuel refund	(9.5		)
DOE settlement refund	(1.9		)
Total electric rate increase	$	17.4

^(a)

Includes Interchange Agreement billings. The Interchange Agreement is a Federal Energy Regulatory Commission (FERC) tariff under which NSP-Wisconsin and its affiliate, NSP-Minnesota, own and operate a single integrated electric generation and transmission system and both companies pay a pro-rata share of system capital and operating costs. For financial reporting purposes, these expenses are included in operating and maintenance expenses.



Natural Gas Rate Request (Millions of Dollars)	Request
Environmental remediation expenses	$	4.8
Total natural gas rate increase	$	4.8

A PSCW decision is anticipated in the fourth quarter of 2016.

PSCo

Pending Regulatory Proceedings — CPUC

PSCo – Annual Electric Earnings Tests — As part of an annual earnings test, PSCo must share with customers’ earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. In April 2016, PSCo filed the 2015 earnings test, proposing an electric customer refund obligation of $14.9 million, subject to review by the CPUC. The proposed refund obligation related to the 2015 earnings test was accrued for as of March 31, 2016. The current estimate of the 2016 earnings test, based on annual forecasted information, did not result in the recognition of a liability as of March 31, 2016.

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SPS

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

SPS – Texas 2015 Electric Rate Case — In December 2014, SPS filed a retail electric rate case in Texas seeking an overall increase in annual revenue of approximately $64.8 million, or 6.7 percent. The filing was based on a historic test year (HTY) ending June 2014, adjusted for known and measurable changes, a ROE of 10.25 percent, an electric rate base of approximately $1.6 billion and an equity ratio of 53.97 percent.

SPS requested a waiver of the PUCT post-test year adjustment rule which would allow for inclusion of $392 million (SPS total company) additional capital investment for the period July 1, 2014 through Dec. 31, 2014. In June 2015, SPS revised its requested rate increase to $42.1 million.

In December 2015, the PUCT made the following decisions:


•	Disallowed SPS’ proposed adjustment to jurisdictional allocation factors to reflect Golden Spread Electric Cooperative, Inc.’s wholesale load reductions from 500 MW to 300 MW, effective June 1, 2015;


•	Disallowed incentive compensation;


•	Approved an equity ratio of 51.00 percent instead of the actual 53.97 percent; and


•	A ROE of 9.70 percent.

The following table reflects the ALJs’ position and PUCT’s decision:



	ALJs’ Proposal			PUCT
(Millions of Dollars)	for Decision			Decision
SPS’ revised rate request	$	42.1		$	42.1
Investment for capital expenditures — post-test year adjustments	(8.9		)	(8.9		)
Lower ROE	(6.3		)	(6.3		)
Lower capital structure	—			(3.7		)
Annual incentive compensation	(0.2		)	(0.3		)
O&M expense adjustments	(4.6		)	(4.6		)
Depreciation expense	(2.7		)	(2.7		)
Property taxes	(0.9		)	(0.9		)
Revenue adjustments	(1.1		)	(1.6		)
Wholesale load reductions	—			(11.5		)
Southwest Power Pool, Inc. (SPP) transmission expansion plan	(4.2		)	(4.2		)
Other, net	1.4			(1.2		)
Total, gross of rate case expenses	$	14.6		$	(3.8	)
Adjustment to move rate case expenses to a separate docket	(0.2		)	(0.2		)
Total, net of rate case expenses	$	14.4		$	(4.0	)
New depreciation rates	(11.2		)	(11.2		)
Earnings impact	$	3.2		$	(15.2	)

In January 2016, SPS filed its motion for rehearing on capital structure, incentive compensation and known and measurable adjustments, including wholesale load reductions and post test-year capital additions. In February 2016, the PUCT orally denied requests for rehearing. A second motion for rehearing was filed by SPS in March 2016. The PUCT took no action on the motions for rehearing and, as a result, the motions were overruled by operation of law. In April 2016, SPS filed an appeal of the PUCT’s order on rehearing.

SPS – Texas 2016 Electric Rate Case — In February 2016, SPS filed a retail electric, non-fuel rate case in Texas with each of its Texas municipalities and the PUCT requesting an overall increase in annual base rate revenue of approximately $71.9 million, or 14.4 percent. The filing is based on a HTY ended Sept. 30, 2015, a requested ROE of 10.25 percent, an electric rate base of approximately $1.7 billion, and an equity ratio of 53.97 percent. In April 2016, SPS revised its request to $68.6 million. The modification reflects actual results for the period of Oct. 1, 2015 through Dec. 31, 2015.

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The following table summarizes the revised net request:



(Millions of Dollars)	Request
Capital expenditure investments	$	38.9
Change in jurisdictional allocation factors	9.8
Changes in ROE and capital structure	11.6
Estimated rate case expenses	4.5
Other, net	3.8
Total	$	68.6

Key dates in the procedural schedule are as follows:


•	Intervenor direct testimony — Aug. 16, 2016;


•	PUCT Staff direct testimony — Aug. 23, 2016;


•	PUCT Staff and Intervenors’ cross-rebuttal testimony — Sept. 7, 2016;


•	SPS’ Rebuttal testimony — Sept. 9, 2016; and


•	Hearings — Sept. 27 - Oct. 7, 2016.

The final rates established at the end of the case will be made effective relating back to July 20, 2016. A PUCT decision is expected in the first quarter of 2017.

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

SPS – New Mexico 2015 Electric Rate Case — In October 2015, SPS filed an electric rate case with the NMPRC seeking an increase in non-fuel base rates of $45.4 million. The proposed increase would be offset by a decrease in base fuel revenue of approximately $21.1 million. The decrease in base fuel revenue will be reflected in adjustments collected through the fuel and purchased power cost adjustment clause (FPPCAC). The rate filing is based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.25 percent, an electric jurisdictional rate base of approximately $734 million and an equity ratio of 53.97 percent.

On May 2, 2016, SPS, the NMPRC Staff and all other parties filed a unanimous black-box stipulation that resolves all issues in the case. Under the stipulation, SPS will implement a non-fuel base rate increase of $23.5 million and a decrease in base fuel revenue of approximately $21.1 million. The decrease in base fuel revenue will be reflected in adjustments collected through the FPPCAC. The stipulation places no restriction on when SPS may file its next base rate case.

The stipulation is subject to approval by the NMPRC. A decision by the NMPRC on the settlement and implementation of final rates is expected by August 2016.

Pending and Recently Concluded Regulatory Proceedings — FERC

Midcontinent Independent System Operator, Inc. (MISO) ROE Complaints/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners (TOs), including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for regional transmission organization (RTO) membership and being an independent transmission company), effective Nov. 12, 2013.

In June 2014 the FERC adopted a new ROE methodology, which requires electric utilities to use a two-step discounted cash flow analysis that incorporates both short-term and long-term growth projections to estimate the cost of equity.

In December 2015, an ALJ initial decision recommended the FERC approve a ROE of 10.32 percent. A FERC order is expected to be issued no earlier than late 2016 or 2017.

Certain MISO TOs separately requested FERC approval of a 50 basis point ROE adder for RTO membership, which was approved effective Jan. 6, 2015, subject to the outcome of the ROE complaint. Certain intervenors sought rehearing of this order, which the FERC denied in 2015.

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In February 2015, a second complaint was filed seeking to reduce the MISO region ROE from 12.38 percent to 8.67 percent, prior to any adder. The FERC set the second complaint for hearings, and established a refund effective date of Feb. 12, 2015. The MPUC, the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission and the DOC joined a joint complainant/intervenor initial brief recommending an ROE of either 8.82 percent or 8.81 percent. FERC staff recommended a ROE of 8.78 percent. The MISO TOs recommended a ROE of 10.92 percent. An ALJ initial decision is expected in June 2016 with a FERC decision expected no earlier than late 2016 or 2017.

NSP-Minnesota has recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE, including the RTO membership adder, as of March 31, 2016. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $8 million and $10 million, annually, for the NSP System.

SPP Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded (or “sponsored”) transmission upgrades may be recovered, in part, from other SPP customers whose transmission service depends on capacity enabled by the sponsored upgrade. The SPP OATT has allowed SPP to collect charges since 2008, but to date SPP has not charged its customers any amounts attributable to these upgrades.

On April 1, 2016, SPP filed a request with the FERC to recover the charges not billed since 2008. The SPP has indicated the investment subject to the retroactive charges could total $720 million, but the SPP filing does not quantify the charges that might be billed to individual SPP transmission customers, including SPS. SPS could also collect revenues as it has constructed a sponsored upgrade. On April 22, 2016, SPS protested the SPP filing, arguing that SPP has failed to establish that it is justified. Due to the limited information available and lack of historical precedent, the potential loss to SPS, if any, is not currently estimable. No accrual has been recorded for this matter.


6.	Commitments and Contingencies

Except to the extent noted below and in Note 5 above, 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, 2015, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, 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 (PPAs)

Under certain PPAs, 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 PPAs create a variable interest in the associated independent power producing entity.

The Xcel Energy utility subsidiaries had approximately 3,698 MW of capacity under long-term PPAs as of March 31, 2016 and Dec. 31, 2015, 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 2033.

Guarantees and Bond 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, 2016 and Dec. 31, 2015, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.

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



(Millions of Dollars)	March 31, 2016		Dec. 31, 2015
Guarantees issued and outstanding	$	9.0	$	12.5
Current exposure under these guarantees	0.1		0.1
Bonds with indemnity protection	42.3		41.3

Other Indemnification Agreements

Xcel Energy Inc. and its subsidiaries provide 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.

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 Site) includes property owned by NSP-Wisconsin, previously operated as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park); and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments).

In 2010, the United States Environmental Protection Agency (EPA) issued its Record of Decision (ROD), including their preferred remedy for the Sediments which is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). A wet conventional dredging only remedy (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study, is another potential remedy.

In 2012, under a settlement agreement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area (which includes the Upper Bluff and Kreher Park areas of the Site). The excavation and containment remedies are complete, and a long-term groundwater pump and treatment program is now underway. The final design was approved by the EPA in 2015. The current cost estimate for the cleanup of the Phase I Project Area is approximately $68.1 million, of which approximately $50.5 million has already been spent.

Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay for or perform the cleanup of the Sediments and which remedy will be implemented. The EPA’s ROD includes estimates that the cost of the Hybrid Remedy is between $63 million and $77 million, with a potential deviation in such estimated costs of up to 50 percent higher or 30 percent lower. NSP-Wisconsin believes the Hybrid Remedy is not safe or feasible to implement. In 2015, NSP-Wisconsin constructed a breakwater at the site to serve as wave attenuation and containment for a wet dredge pilot study and full scale sediment remedy at the site. Equipment mobilization for the wet dredge pilot study commenced in April 2016.

Three other PRPs have contributed $15.9 million to the remediation of the site, as a result of litigation and settlements approved by the U.S. District Court for the Western District of Wisconsin in 2015. NSP-Wisconsin’s litigation effort against other PRPs is now complete.

At March 31, 2016 and Dec. 31, 2015, NSP-Wisconsin had recorded a liability of $94.2 million and $94.4 million, respectively, for the Site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $17.2 million and $17.0 million, respectively, were considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the timing of expenditures are subject to change. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the remediation cost of the entire site.

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NSP-Wisconsin has deferred the estimated site remediation costs as a regulatory asset. The PSCW has consistently authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Site. In a December 2012 decision, the PSCW agreed to allow NSP-Wisconsin to pre-collect certain costs, to amortize costs over a ten-year period, and to apply a three percent carrying cost to the unamortized regulatory asset. In December 2015, the PSCW approved NSP-Wisconsin’s 2016 rate case request for an increase to the annual recovery for MGP clean-up costs from $4.7 million to $7.6 million. In April 2016, NSP-Wisconsin filed a limited natural gas rate case for recovering additional expenses associated with remediating the Site. If approved, the annual recovery of MGP clean-up costs would increase from $7.6 million in 2016 to $12.4 million in 2017.

Fargo, N.D. MGP Site — In May 2015, underground pipes, tars and impacted soils were discovered in Fargo, N.D., which may be related to a former MGP site operated by NSP-Minnesota or a prior company. NSP-Minnesota has removed the impacted soils and other materials from the project area. NSP-Minnesota is undertaking further investigation of the location of the historic MGP site and nearby properties. In October 2015, NSP-Minnesota initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota agreed to the parties’ request for a stay of the litigation until July 2016 to allow NSP-Minnesota time to further investigate site conditions.

As of March 31, 2016 and Dec. 31, 2015, NSP-Minnesota had recorded a liability of $2.2 million and $2.7 million, respectively, related to further investigation and additional planned activities. Uncertainties include the nature and cost of the additional remediation efforts that may be necessary, the ability to recover costs from insurance carriers and the potential for contributions from entities that may be identified as PRPs. Therefore, the total cost of remediation, NSP-Minnesota’s potential liability and amounts allocable to the North Dakota and Minnesota jurisdictions related to the site cannot currently be reasonably estimated. In December 2015, the NDPSC approved NSP-Minnesota’s request to defer the portion of investigation and response costs allocable to the North Dakota jurisdiction.

Environmental Requirements

Air

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, 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. In their first regional haze state implementation plans (SIPs), Colorado, Minnesota and Texas identified the Xcel Energy facilities that will have to reduce SO₂, NOx and particulate matter (PM) emissions under BART and set emissions limits for those facilities.

PSCo

In 2011, the Colorado Air Quality Control Commission approved a SIP (the Colorado SIP) that included the Clean Air Clean Jobs Act (CACJA) emission reduction plan as satisfying regional haze requirements for facilities included within the CACJA plan. In addition, the Colorado SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the Colorado SIP in 2012. Emission controls at Hayden Unit 1 were placed into service in November 2015 and Hayden Unit 2 is expected to be placed into service in late 2016, at an estimated combined cost of $75.2 million, completing the pollution control equipment required on PSCo plants under the CACJA. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.

NSP-Minnesota

In 2009, the Minnesota Pollution Control Agency (MPCA) approved a SIP (the Minnesota SIP) and submitted it to the EPA for approval. The MPCA’s source-specific BART limits for Sherco Units 1 and 2 require combustion controls for NOx and scrubber upgrades for SO₂. The MPCA supplemented its Minnesota SIP in 2012, determining that CSAPR meets BART requirements, but also implementing its source-specific BART determination for Sherco Units 1 and 2 from the 2009 Minnesota SIP. In June 2012, the EPA approved the Minnesota SIP for EGUs and also approved the source-specific emission limits for Sherco Units 1 and 2. The combustion controls were installed first and the scrubber upgrades were completed in December 2014, at a cost of $46.9 million. NSP-Minnesota has included these costs for recovery in rate proceedings.

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 (Eighth Circuit). In January 2016, the Eighth Circuit issued their opinion which upheld the EPA’s approval of the Minnesota SIP. In March 2016, after granting a rehearing request, the Eighth Circuit issued a revised opinion that included additional explanation and continued to uphold the EPA’s approval of the Minnesota SIP.

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SPS

Texas 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 December 2014, the EPA proposed to approve the BART portion of the Texas SIP, with the exception that the EPA would substitute CSAPR compliance for Texas’ reliance on CAIR. In January 2016, the EPA adopted a final rule that defers its approval of CSAPR compliance as BART until the EPA considers further adjustments to CSAPR emission budgets in relation to the 2012 particle national ambient air quality standard (NAAQS). In March 2016, the EPA requested information under the Clean Air Act (CAA) related to EGUs at SPS’ plants. SPS replied to the request in April 2016 and identified Harrington Units 1 and 2, Jones Units 1 and 2, Nichols Unit 3 and Plant X Unit 4 as BART-eligible units. These units will be evaluated based on their impact on visibility. Additional emission control equipment under the EPA’s BART guidelines for PM, SO₂ and NOx could be required if a unit is determined to “cause or contribute” to visibility impairment. Xcel Energy cannot evaluate the impact of additional emission controls until the EPA concludes their evaluation of BART. The EPA is expected to issue a proposed rule in December 2016.

In December 2014, the EPA proposed to disapprove the reasonable progress portions of the Texas SIP and instead adopt a federal implementation plan (FIP). In January 2016, the EPA adopted a final rule establishing a FIP for the state of Texas. As part of this final rule, the EPA imposed SO₂ emission limitations that reflect the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be approximately $600 million. In March 2016, SPS appealed the EPA’s decision and has asked the court to stay the final rule while it is being reviewed by the court. In addition, SPS filed a petition with the EPA requesting reconsideration of the final rule. SPS believes these costs would be recoverable through regulatory mechanisms if required, and therefore does not expect a material impact on results of operations, financial position or cash flows.

Reasonably Attributable Visibility Impairment (RAVI) — RAVI is intended to address observable impairment from a specific source such as distinct, identifiable plumes from a source’s stack to a national park. In 2009, the United States Department of the Interior 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.

In December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota (Minnesota District Court) 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.

In May 2015, NSP-Minnesota, the EPA and the six environmental advocacy organizations filed a settlement agreement in the Minnesota District Court. The agreement anticipates a federal rulemaking that would impose stricter SO₂ emission limits on Sherco Units 1, 2 and 3, without making a RAVI attribution finding or a RAVI BART determination. The emission limits for Units 1 and 2 reflect the success of a recently completed control project. The Unit 3 emission limits will be met through changes in the operation of the existing scrubber. The Minnesota District Court issued an order staying the litigation for the time needed to complete the actions required by the settlement agreement. The plaintiffs agreed to withdraw their complaint with prejudice when those actions are completed. Plaintiffs also agreed not to request a RAVI certification for Sherco Units 1, 2 and/or 3 in the future.

In March 2016, the EPA adopted a final rule which set the agreed-upon SO₂ emission limits. As a result, the Minnesota District Court dismissed the litigation with prejudice in March 2016. NSP-Minnesota does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows.

Implementation of the NAAQS for SO₂ — The EPA adopted a more stringent NAAQS for SO₂ in 2010. In 2013, the EPA designated areas as not attaining the revised NAAQS, which did not include any areas where Xcel Energy operates power plants. However, many other areas of the country were unable to be classified by the EPA due to a lack of air monitors.

Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and under a consent decree the EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant and SPS’ Tolk and Harrington plants. The Pawnee plant recently installed an SO₂ scrubber and the Tolk and Harrington Plants utilize low sulfur coal to reduce SO₂ emissions. In February 2016, the EPA notified the Texas Commission on Environmental Quality (TCEQ) and the Colorado Department of Health and Environment of its preliminary SO₂ designations. The EPA has proposed to designate the area near the Tolk plant as meeting the standard and the areas near the Harrington and Pawnee plants as “unclassifiable.” If finalized as proposed, the unclassifiable areas will be monitored for three years and final designations will be made by December 2020. The EPA’s final decision is expected by July 2016.

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If an area is designated nonattainment, the respective states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan, which would be due in 18 months, designed to achieve the NAAQS within five years. The TCEQ could require additional SO₂ controls on one or more of the units at Tolk and Harrington. The areas near the remaining Xcel Energy power plants will be evaluated in the next designation phase, ending December 2017. The remaining plants, PSCo’s Comanche and Hayden plants along with NSP-Minnesota’s King and Sherco plants, utilize scrubbers to control SO₂ emissions. Xcel Energy cannot evaluate the impacts until the designation of nonattainment areas is made and any required state plans are developed. Xcel Energy believes that, should SO₂ control systems be required for a plant, compliance costs will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.

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.

Employment, Tort and Commercial Litigation

Pacific Northwest FERC Refund Proceeding — A complaint with the FERC posed that sales made in the Pacific Northwest in 2000 and 2001 through bilateral contracts were unjust and unreasonable under the Federal Power Act. The City of Seattle (the City) alleges between $34 million to $50 million in sales with PSCo is subject to refund. In 2003, the FERC terminated the proceeding, although it was later remanded back to the FERC in 2007 by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).

In May 2015, in the remand proceeding, the FERC issued an order rejecting the City’s claim that any of the sales made resulted in an excessive burden and concluded that the City failed to establish a causal link between any contracts and any claimed unlawful market activity. In June 2015, the City requested the FERC grant rehearing of its order, which the FERC denied in December. The City subsequently appealed this decision to the Ninth Circuit on Feb. 22, 2016.

Also in December 2015, the Ninth Circuit issued an order and held that the standard of review applied by the FERC to the contracts which the City was challenging is appropriate. The Ninth Circuit dismissed questions concerning whether the FERC properly established the scope of the hearing, and determined that the challenged orders are preliminary and that the Ninth Circuit lacks jurisdiction to review evidentiary decisions until after the FERC’s proceedings are final. The City joined the State of California in its request seeking rehearing of this order.

Preliminary calculations of the City’s claim for refunds from PSCo are approximately $28 million, excluding 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, notwithstanding PSCo’s view that the City 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 scope of the proceeding established by FERC is being challenged in 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 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.

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Gas Trading Litigation — e prime, inc. (e prime) is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing, but has not engaged in natural gas trading or marketing activities since 2003. Thirteen lawsuits were commenced against e prime and Xcel Energy (and NSP-Wisconsin, in two instances) between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. The cases were consolidated in U.S. District Court in Nevada. In 2009, five of the cases were settled and one was dismissed. The U.S. District Court, in 2011, issued an order dismissing entirely six of the remaining seven lawsuits, and partially dismissing the seventh. Plaintiffs appealed the dismissals to the Ninth Circuit, which reversed the U.S. District Court. The matter was ultimately heard by the U.S. Supreme Court in early 2015, which agreed with the Ninth Circuit and remanded the matter to the U.S. District Court. In September 2015, the District Court held a status conference and set deadlines for certain litigation related activities in 2016. Trial dates have not yet been set, but are not expected to occur prior to early 2017. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote with respect to this matter.

Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in Denver State Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric service agreements entered into by PSCo and various developers. The dispute involves assigned interests in those claims by over fifty developers. On May 9, 2016, the district court granted PSCo’s motion to dismiss the lawsuit, essentially concluding that jurisdiction over this dispute resides with the CPUC. It is uncertain whether plaintiffs will appeal this decision. PSCo has concluded that a loss is remote with respect to this matter as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms as the line extension payments from developers, for which DRC is seeking a refund, have served to reduce rate base over the period in dispute. The amount or range in dispute is presently unknown and no accrual has been recorded for this matter.


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, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	2,750		$	2,750
Amount outstanding at period end	183			846
Average amount outstanding	774			601
Maximum amount outstanding	1,183			1,360
Weighted average interest rate, computed on a daily basis	0.73		%	0.48		%
Weighted average interest rate at period end	0.63			0.82

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, 2016 and Dec. 31, 2015, there were $29 million of letters of credit outstanding under the credit facilities. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

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.

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At March 31, 2016, 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.	$	1,000	$	25	$	975
PSCo	700		4		696
NSP-Minnesota	500		91		409
SPS	400		87		313
NSP-Wisconsin	150		5		145
Total	$	2,750	$	212	$	2,538


^(a)	These credit facilities expire in October 2019.


^(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, 2016 and Dec. 31, 2015.

Long-Term Borrowings

In March 2016, Xcel Energy Inc. issued $400 million of 2.4 percent senior notes due March 15, 2021 and $350 million of 3.3 percent senior notes due June 1, 2025.


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 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 prices.

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 a NAV methodology, which takes 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. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days 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, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity.

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.

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

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 transmission congestion instruments, generally referred to as financial transmission rights (FTRs), purchased from MISO, PJM Interconnection, LLC, Electric Reliability Council of Texas, SPP and New York Independent System Operator. Electric commodity derivatives held by SPS include FTRs purchased from SPP. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to 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. The 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 settlements for non-trading FTRs are included in fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, 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 (PI) 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. NSP-Minnesota uses the MPUC approved 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 $322.7 million and $328.8 million at March 31, 2016 and Dec. 31, 2015, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $100.3 million and $100.2 million at March 31, 2016 and Dec. 31, 2015, 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, 2016 and Dec. 31, 2015:



	March 31, 2016
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	11,899	$	11,899	$	—	$	—	$	—	$	11,899
Commingled funds	390,345		—		—		—		395,709		395,709
International equity funds	264,340		—		—		—		242,312		242,312
Private equity investments	108,882		—		—		—		158,915		158,915
Real estate	73,577		—		—		—		100,576		100,576
Debt securities:
Government securities	24,320		—		23,213		—		—		23,213
U.S. corporate bonds	76,952		—		70,723		—		—		70,723
International corporate bonds	18,117		—		17,343		—		—		17,343
Municipal bonds	47,088		—		49,902		—		—		49,902
Asset-backed securities	2,841		—		2,836		—		—		2,836
Mortgage-backed securities	11,065		—		11,407		—		—		11,407
Equity securities:
Common stock	481,968		649,015		—		—		—		649,015
Total	$	1,511,394	$	660,914	$	175,424	$	—	$	897,512	$	1,733,850


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $132.8 million of equity investments in unconsolidated subsidiaries and $51.1 million of miscellaneous investments.


^(b)	Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07.



	Dec. 31, 2015
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	27,484	$	27,484	$	—	$	—	$	—	$	27,484
Commingled funds	392,838		—		—		—		410,634		410,634
International equity funds	259,114		—		—		—		231,122		231,122
Private equity investments	105,965		—		—		—		157,528		157,528
Real estate	61,816		—		—		—		84,750		84,750
Debt securities:
Government securities	24,444		—		21,356		—		—		21,356
U.S. corporate bonds	73,061		—		65,276		—		—		65,276
International corporate bonds	13,726		—		12,801		—		—		12,801
Municipal bonds	49,255		—		51,589		—		—		51,589
Asset-backed securities	2,837		—		2,830		—		—		2,830
Mortgage-backed securities	11,444		—		11,621		—		—		11,621
Equity securities:
Common stock	473,615		647,159		—		—		—		647,159
Total	$	1,495,599	$	674,643	$	165,473	$	—	$	884,034	$	1,724,150


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $130.0 million of equity investments in unconsolidated subsidiaries and $48.9 million of miscellaneous investments.


^(b)	Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07.

For the three months ended March 31, 2016 and 2015 there were no Level 3 nuclear decommissioning fund investments and no transfers of amounts between levels.

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The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at March 31, 2016:



	Final Contractual Maturity
(Thousands of Dollars)	Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years			Total
Government securities	$	—	$	—	$	3,144	$	20,069		$	23,213
U.S. corporate bonds	—		18,909		56,102		(4,288		)	70,723
International corporate bonds	—		2,795		11,505		3,043			17,343
Municipal bonds	151		266		16,323		33,162			49,902
Asset-backed securities	—		—		2,836		—			2,836
Mortgage-backed securities	—		—		—		11,407			11,407
Debt securities	$	151	$	21,970	$	89,910	$	63,393		$	175,424

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, 2016, accumulated other comprehensive losses related to interest rate derivatives included $3.5 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 unsettled hedges, as applicable.

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.

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, FTRs, vehicle fuel and weather derivatives.

At March 31, 2016, 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, 2016 and 2015.

At March 31, 2016, net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net losses 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.

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The following table details the gross notional amounts of commodity forwards, options and FTRs at March 31, 2016 and Dec. 31, 2015:


^(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.

The following tables detail the impact of derivative activity during the three months ended March 31, 2016 and 2015, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:



	Three Months Ended March 31, 2016
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	1,485	^(a)	$	—		$	—
Vehicle fuel and other commodity	(6		)	—			57		^(b)	—			—
Total	$	(6	)	$	—		$	1,542		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	1,009		^(c)
Electric commodity	—			(265		)	—			8,631		^(d)	—
Natural gas commodity	—			(2,702		)	—			11,666		^(e)	(5,024		)	^(e)
Total	$	—		$	(2,967	)	$	—		$	20,297		$	(4,015	)



	Three Months Ended March 31, 2015
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax (Gains) Losses Reclassified into Income During the Period from:							Pre-Tax Gains Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)				Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	941	^(a)	$	—			$	—
Vehicle fuel and other commodity	(18		)	—			26		^(b)	—				—
Total	$	(18	)	$	—		$	967		$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—			$	3,880	^(c)
Electric commodity	—			(9,471		)	—			(5,123		)	^(d)	—
Natural gas commodity	—			(216		)	—			(8,831		)	^(e)	8,991		^(e)
Total	$	—		$	(9,687	)	$	—		$	(13,954	)		$	12,871


^(a)	Amounts are recorded to interest charges.


^(b)	Amounts are recorded to O&M expenses.


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


^(d)	Amounts are recorded to electric fuel and purchased power. These derivative settlement gain and loss amounts are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

^(e)

Amounts for the three months ended March 31, 2016 and 2015 included an immaterial amount of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three months ended March 31, 2016 and 2015 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.

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Xcel Energy had no derivative instruments designated as fair value hedges during the three months ended March 31, 2016 and 2015. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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, 2016, one of Xcel Energy’s 10 most significant counterparties for these activities, comprising $16.7 million or 7 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Seven of the 10 most significant counterparties, comprising $67.2 million or 30 percent of this credit exposure, were not rated by these external agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. The remaining two most significant counterparties, comprising $16.5 million or 7 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external and internal analysis. Nine of these significant counterparties are municipal or cooperative electric entities or other utilities.

Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary is unable to maintain its credit ratings. At March 31, 2016 and Dec. 31, 2015, there were no derivative instruments in a liability position that would have required the posting of collateral or settlement of applicable outstanding contracts if the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment grade.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of March 31, 2016 and Dec. 31, 2015.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at March 31, 2016:

March 31, 2016

Fair Value

Fair Value Total

Counterparty Netting ^(b)

Total

(Thousands of Dollars)

Level 1

Level 2

Level 3

Current derivative assets

Other derivative instruments:

Commodity trading

1,054