UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended ~~June 30, 2017~~March 31, 2018



¨	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, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth 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)		Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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 ~~July 24, 2017~~April 23, 2018
Common Stock, $2.50 par value		~~507,762,881~~508,856,950 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	98
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3432
Item 3 —	Quantitative and Qualitative Disclosures about Market Risk	5250
Item 4 —	Controls and Procedures	5250

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	5350
Item 1A —	Risk Factors	5350
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	5351
Item 6 —	Exhibits	5451

SIGNATURES		5552

	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)
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (amounts in millions, except per share data)													XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (amounts in millions, except per share data)

	Three Months Ended June 30						Six Months Ended June 30						Three Months Ended March 31
	2017			2016			2017			2016			2018			2017
Operating revenues
Electric	$	2,338,017		$	2,224,142		$	4,637,077		$	4,409,261		$	2,270		$	2,299
Natural gas	289,839			258,899			915,542			824,588			662			626
Other	17,072			16,808			38,731			38,273			19			21
Total operating revenues	2,644,928			2,499,849			5,591,350			5,272,122			2,951			2,946

Operating expenses
Electric fuel and purchased power	919,099			855,968			1,844,320			1,717,820			932			925
Cost of natural gas sold and transported	114,320			90,071			479,454			402,188			375			365
Cost of sales — other	8,178			8,332			16,765			16,577			8			9
Operating and maintenance expenses	578,133			596,978			1,164,563			1,174,388			557			580
Conservation and demand side management expenses	64,860			55,916			132,393			113,352			71			68
Depreciation and amortization	365,720			322,534			730,924			642,554			383			365
Taxes (other than income taxes)	134,926			138,469			277,020			283,792			145			142
Total operating expenses	2,185,236			2,068,268			4,645,439			4,350,671			2,471			2,454

Operating income	459,692			431,581			945,911			921,451			480			492

Other income, net	2,608			1,560			9,054			5,810			1			1
Equity earnings of unconsolidated subsidiaries	7,541			9,617			15,416			22,799			6			8
Allowance for funds used during construction — equity	16,386			14,730			30,699			27,843			23			14

Interest charges and financing costs
Interest charges — includes other financing costs of $5,876, $6,630, $11,734 and $12,966, respectively	164,195			162,980			330,129			319,423
Interest charges — includes other financing costs of $6 and $6, respectively													171			166
Allowance for funds used during construction — debt	(7,613		)	(6,684		)	(14,635		)	(12,674		)	(11		)	(7		)
Total interest charges and financing costs	156,582			156,296			315,494			306,749			160			159

Income before income taxes	329,645			301,192			685,586			671,154			350			356
Income taxes	102,389			104,397			219,053			233,047			59			117
Net income	$	227,256		$	196,795		$	466,533		$	438,107		$	291		$	239

Weighted average common shares outstanding:
Basic	508,542			508,930			508,411			508,789			509			508
Diluted	509,135			509,490			508,955			509,311			509			509

Earnings per average common share:
Basic	$	0.45		$	0.39		$	0.92		$	0.86		$	0.57		$	0.47
Diluted	0.45			0.39			0.92			0.86			0.57			0.47

Cash dividends declared per common share	$	0.36		$	0.34		$	0.72		$	0.68		$	0.38		$	0.36

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (amounts in thousands)
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (amounts in millions)									XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (amounts in millions)

	Three Months Ended June 30				Six Months Ended June 30				Three Months Ended March 31
	2017		2016		2017		2016		2018		2017
Net income	$	227,256	$	196,795	$	466,533	$	438,107	$	291	$	239

Other comprehensive income

Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $608, $550, $1,223 and $407, respectively	956		865		1,904		1,076
Amortization of losses included in net periodic benefit cost, net of tax of $0 and $1, respectively									1		1

Derivative instruments:
Net fair value increase, net of tax of $17, $7, $17 and $5, respectively	26		12		26		8
Reclassification of losses to net income, net of tax of $511, $594, $1,045 and $1,198, respectively	803		936		1,628		1,874
Reclassification of losses to net income, net of tax of $0 and $1, respectively									—		1
	829		948		1,654		1,882
Marketable securities:
Net fair value increase, net of tax of $0, $0, $0 and $0, respectively	1		—		1		—

Other comprehensive income	1,786		1,813		3,559		2,958		1		2
Comprehensive income	$	229,042	$	198,608	$	470,092	$	441,065	$	292	$	241

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (amounts in thousands)
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (amounts in millions)							XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (amounts in millions)

	Six Months Ended June 30						Three Months Ended March 31
	2017			2016			2018			2017
Operating activities
Net income	$	466,533		$	438,107		$	291		$	239
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	738,280			650,336			387			369
Conservation and demand side management program amortization	1,509			2,323
Nuclear fuel amortization	57,003			58,267			31			31
Deferred income taxes	309,239			252,889			59			194
Amortization of investment tax credits	(2,557		)	(2,613		)
Allowance for equity funds used during construction	(30,699		)	(27,843		)	(23		)	(14		)
Equity earnings of unconsolidated subsidiaries	(15,416		)	(22,799		)	(6		)	(8		)
Dividends from unconsolidated subsidiaries	23,507			22,910			9			12
Share-based compensation expense	31,892			24,454			6			18
Net realized and unrealized hedging and derivative transactions	217			3,903
Other, net	(2,441		)	(388		)	(1		)	4
Changes in operating assets and liabilities:
Accounts receivable	16,906			35,042			(71		)	3
Accrued unbilled revenues	121,333			65,159			159			174
Inventories	65,433			81,880			118			88
Other current assets	(84,024		)	69,493			1			(77		)
Accounts payable	(52,349		)	27,805			(42		)	(144		)
Net regulatory assets and liabilities	1,498			34,264			147			18
Other current liabilities	(190,184		)	(151,589		)	(17		)	(43		)
Pension and other employee benefit obligations	(140,479		)	(108,562		)	(146		)	(149		)
Change in other noncurrent assets	(6,676		)	(6,363		)	2			—
Change in other noncurrent liabilities	(16,706		)	(21,649		)	(17		)	3
Net cash provided by operating activities	1,291,819			1,425,026			887			718

Investing activities
Utility capital/construction expenditures	(1,473,793		)	(1,413,129		)	(883		)	(749		)
Proceeds from insurance recoveries	—			1,595
Allowance for equity funds used during construction	30,699			27,843			23			14
Purchases of investment securities	(368,266		)	(319,880		)	(185		)	(173		)
Proceeds from the sale of investment securities	350,448			262,321			179			168
Investments in WYCO Development LLC and other	(7,683		)	(2,170		)
Investments in unconsolidated subsidiaries and other							(3		)	(3		)
Other, net	(5,483		)	100			(3		)	(5		)
Net cash used in investing activities	(1,474,078		)	(1,443,320		)	(872		)	(748		)

Financing activities
Proceeds from (repayments of) short-term borrowings, net	392,000			(399,000		)
Proceeds from issuance of long-term debt	394,046			1,337,430
Repayments of long-term debt	(250,397		)	(579,976		)
Repurchases of common stock	(2,943		)	(789		)
Proceeds from short-term borrowings, net							211			213
Dividends paid	(355,250		)	(335,113		)	(175		)	(173		)
Other	(18,291		)	(12,487		)	(18		)	(21		)
Net cash provided by financing activities	159,165			10,065			18			19

Net change in cash and cash equivalents	(23,094		)	(8,229		)	33			(11		)
Cash and cash equivalents at beginning of period	84,476			84,940			83			85
Cash and cash equivalents at end of period	$	61,382		$	76,711		$	116		$	74

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(301,350	)	$	(293,954	)	$	(181	)	$	(174	)
Cash (paid) received for income taxes, net	(3,853		)	61,345

Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable	$	233,250		$	252,370		$	241		$	186
Issuance of common stock for equity awards	18,505			13,497			20			12

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) (amounts in thousands, except share and per share data)
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) (amounts in millions, except share and per share data)							XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) (amounts in millions, except share and per share data)

	June 30, 2017			Dec. 31, 2016			March 31, 2018			Dec. 31, 2017
Assets
Current assets
Cash and cash equivalents	$	61,382		$	84,476		$	116		$	83
Accounts receivable, net	759,378			776,289			868			797
Accrued unbilled revenues	608,499			729,832			605			764
Inventories	542,044			604,226			492			610
Regulatory assets	375,020			363,655			422			424
Derivative instruments	78,487			38,224			28			44
Prepaid taxes	196,247			106,697			63			68
Prepayments and other	135,493			138,682			188			183
Total current assets	2,756,550			2,842,081			2,782			2,973

Property, plant and equipment, net	33,543,843			32,841,750			34,679			34,329

Other assets
Nuclear decommissioning fund and other investments	2,231,588			2,091,858			2,404			2,397
Regulatory assets	3,023,128			3,080,867			2,965			3,005
Derivative instruments	50,410			50,189			49			48
Other	255,470			248,532			280			278
Total other assets	5,560,596			5,471,446			5,698			5,728
Total assets	$	41,860,989		$	41,155,277		$	43,159		$	43,030

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	505,345		$	255,529		$	457		$	457
Short-term debt	784,000			392,000			1,025			814
Accounts payable	973,642			1,044,959			1,027			1,243
Regulatory liabilities	261,171			220,894			270			239
Taxes accrued	339,966			457,392			544			448
Accrued interest	175,849			172,901			147			174
Dividends payable	182,795			172,456			193			183
Derivative instruments	28,019			26,959			30			29
Other	439,917			503,953			429			501
Total current liabilities	3,690,704			3,247,043			4,122			4,088
	��
Deferred credits and other liabilities
Deferred income taxes	7,130,715			6,784,319			3,905			3,845
Deferred investment tax credits	60,659			63,216			57			58
Regulatory liabilities	1,386,675			1,383,212			5,141			5,083
Asset retirement obligations	2,849,532			2,782,229			2,504			2,475
Derivative instruments	136,255			148,146			120			126
Customer advances	190,640			195,214			200			193
Pension and employee benefit obligations	975,606			1,112,366			884			1,042
Other	225,215			223,965			143			145
Total deferred credits and other liabilities	12,955,297			12,692,667			12,954			12,967

Commitments and contingencies
Capitalization
Long-term debt	14,091,833			14,194,718			14,522			14,520
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,762,881 and 507,222,795 shares outstanding at June 30, 2017 and Dec. 31, 2016, respectively	1,269,407			1,268,057
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 508,661,859 and 507,762,881 shares outstanding at March 31, 2018 and Dec. 31, 2017, respectively							1,272			1,269
Additional paid in capital	5,881,475			5,881,494			5,903			5,898
Retained earnings	4,079,068			3,981,652			4,510			4,413
Accumulated other comprehensive loss	(106,795		)	(110,354		)	(124		)	(125		)
Total common stockholders’ equity	11,123,155			11,020,849			11,561			11,455
Total liabilities and equity	$	41,860,989		$	41,155,277		$	43,159		$	43,030

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (amounts in thousands)
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (amounts in millions, shares in thousands)																		XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (amounts in millions, shares in thousands)

	Common Stock Issued						Retained Earnings				Accumulated Other Comprehensive Loss				Total Common Stockholders’ Equity			Common Stock Issued							Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Stockholders’ Equity
	Shares	Par Value		Additional Paid In Capital						Shares					Total Common Stockholders’ Equity			Par Value			Additional Paid In Capital				Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Stockholders’ Equity
Three Months Ended June 30, 2017 and 2016							Retained Earnings
Balance at March 31, 2016	507,953	$	1,269,882	$	5,889,939		$	3,620,421			Accumulated Other Comprehensive Loss	$	(108,608	)		$	10,671,634
Three Months Ended March 31, 2018 and 2017																		Three Months Ended March 31, 2018 and 2017
Balance at Dec. 31, 2016																		507,223		$	1,268	$	5,881		$	3,982		$	(110	)	$	11,021
Net income							196,795								196,795										239						239
Other comprehensive income											1,813				1,813													2			2
Dividends declared on common stock							(173,563		)						(173,563		)								(184		)				(184		)
Issuances of common stock	—	—		(187		)									(187		)	611		1		4									5
Repurchases of common stock																		(71	)	—		(3		)							(3		)
Share-based compensation				6,642											6,642							(9		)	(1		)				(10		)
Balance at June 30, 2016	507,953	$	1,269,882	$	5,896,394		$	3,643,653			$	(106,795	)		$	10,703,134
Balance at March 31, 2017																		507,763		$	1,269	$	5,873		$	4,036		$	(108	)	$	11,070

Balance at March 31, 2017	507,763	$	1,269,407	$	5,872,933		$	4,036,352			$	(108,581	)		$	11,070,111
Balance at Dec. 31, 2017																		507,763		$	1,269	$	5,898		$	4,413		$	(125	)	$	11,455
Net income							227,256								227,256										291						291
Other comprehensive income											1,786				1,786													1			1
Dividends declared on common stock							(183,738		)						(183,738		)								(194		)				(194		)
Issuances of common stock																		921		3		14									17
Repurchases of common stock																		(22	)	—		(1		)							(1		)
Share-based compensation				8,542			(802		)						7,740							(8		)	—						(8		)
Balance at June 30, 2017	507,763	$	1,269,407	$	5,881,475		$	4,079,068			$	(106,795	)		$	11,123,155
Balance at March 31, 2018																		508,662		$	1,272	$	5,903		$	4,510		$	(124	)	$	11,561

See Notes to Consolidated Financial Statements

~~Table of Contents~~

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (Continued)
(amounts in thousands)

Common Stock Issued Retained Earnings Accumulated
Other
Comprehensive
Loss Total
Common
Stockholders’
Equity
Shares Par Value Additional Paid In Capital
Six Months Ended June 30, 2017 and 2016
Balance at Dec. 31, 2015 507,536
$ 1,268,839
$ 5,889,106
$ 3,552,728
$ (109,753 ) $ 10,600,920
Net income 438,107
438,107
Other comprehensive income 2,958
2,958
Dividends declared on common stock (347,182 ) (347,182 )
Issuances of common stock 417
1,043
(3,942 ) (2,899 )
Repurchases of common stock (789 ) (789 )
Share-based compensation 12,019
12,019
Balance at June 30, 2016 507,953
$ 1,269,882
$ 5,896,394
$ 3,643,653
$ (106,795 ) $ 10,703,134

Balance at Dec. 31, 2016 507,223
$ 1,268,057
$ 5,881,494
$ 3,981,652
$ (110,354 ) $ 11,020,849
Net income 466,533
466,533
Other comprehensive income 3,559
3,559
Dividends declared on common stock (367,553 ) (367,553 )
Issuances of common stock 611
1,527
3,510
5,037
Repurchases of common stock (71 ) (177 ) (2,943 ) (3,120 )
Share-based compensation (586 ) (1,564 ) (2,150 )
Balance at June 30, 2017 507,763
$ 1,269,407
$ 5,881,475
$ 4,079,068
$ (106,795 ) $ 11,123,155

See Notes to Consolidated Financial Statements

Table of Contents

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 ~~June 30, 2017~~March 31, 2018 and Dec. 31, ~~2016;~~2017; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three ~~and six~~ months ended ~~June 30, 2017~~March 31, 2018 and ~~2016;~~2017; and its cash flows for the ~~six~~three months ended ~~June 30, 2017~~March 31, 2018 and ~~2016.~~2017. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after ~~June 30, 2017~~March 31, 2018 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, ~~2016~~2017 balance sheet information has been derived from the audited ~~2016~~2017 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2016.~~2017. 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, ~~2016,~~2017, filed with the SEC on Feb. ~~24, 2017.~~23, 2018. 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, ~~2016,~~2017, 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~~Leases — —I ~~In May 2014,~~n February 2016, the Financial Accounting Standards Board (FASB) issued ~~Revenue from Contracts with Customers,~~Leases, Topic ~~606~~842 (Accounting Standards Update (ASU) ~~No. 2014-09)~~, which provides a new framework for the recognition of revenue. Xcel Energy expects its adoption will result in increased disclosures regarding revenue, cash flows and obligations related to arrangements with customers, as well as separate presentation of alternative revenue programs. Xcel Energy has not yet fully determined the impacts of adoption for several aspects of the standard, including a determination whether and how much an evaluation of the collectability of regulated electric and gas revenues will impact the amounts of revenue recognized upon delivery. Xcel Energy currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.

~~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 eliminates the available-for-sale classification for marketable equity securities and also replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, 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 expects that as a result of application of accounting principles for rate regulated entities, changes in the fair value of the securities in the nuclear decommissioning fund, currently classified as available-for-sale, will continue to be deferred to a regulatory asset, and that the overall impacts of the Jan. 1, 2018 adoption will not be material.

~~Leases —~~I~~n 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 most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. Xcel Energy has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the ~~standard.~~standard and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). As such, agreements entered into prior to Jan. 1, ~~2017~~2019 that are currently considered leases are expected to be recognized on the consolidated balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. Xcel Energy expects that similar agreements entered into after Dec. 31, ~~2016~~2018 will generally qualify as leases under the new ~~standard, but has not yet completed its evaluation of certain other contracts, including arrangements for the secondary use of assets, such as land easements.~~standard.

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~~Presentation of Net Periodic Benefit Cost —~~I~~n March 2017, the FASB issued~~ ~~Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07)~~, which establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. Xcel Energy has not yet fully determined the impacts of adoption of the standard, but expects that as a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the current ratemaking treatment and that the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017.

Recently Adopted

~~Stock Compensation~~Revenue Recognition— In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a new framework for the recognition of revenue. Xcel Energy implemented the guidance on a modified retrospective basis on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance. Other than increased disclosures regarding revenues related to contracts with customers, the implementation did not have a significant impact on Xcel Energy’s consolidated financial statements. For related disclosures, see Note 14.

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 eliminated the available-for-sale classification for marketable equity securities and also replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are recognized in earnings. Xcel Energy implemented the guidance on Jan. 1, 2018. As a result of application of accounting principles for rate regulated entities, changes in the fair value of the securities in the nuclear decommissioning fund, historically classified as available-for-sale, continue to be deferred to a regulatory asset, and the overall adoption impacts were not material.

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Presentation of Net Periodic Benefit Cost — In March ~~2016,~~2017, the FASB issued ~~Improvements to Employee Share-Based Payment Accounting,~~Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic ~~718~~715 (ASU No. ~~2016-09),~~2017-07), which ~~simplifies~~establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. As a result of application of accounting ~~and financial statement presentation~~principles for ~~share-based payment transactions. The guidance requires that~~rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the ~~difference between the tax deduction available upon settlement of share-based equity awards~~historical ratemaking treatment, and the ~~tax benefit accumulated over the vesting period~~impacts of adoption will be ~~recognized as an adjustment~~limited to ~~income tax expense. Xcel Energy adopted the guidance in 2016, resulting in immaterial 2016 adjustments to income tax expense and~~ changes in classification of ~~cash flows related to tax withholding~~non-service costs in the consolidated ~~statements~~statement of ~~cash flows~~income. Xcel Energy implemented the new guidance on Jan. 1, 2018, and as a result, $6 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other income, net on the consolidated income statement for the ~~years~~three months ended ~~Dec.~~March 31, ~~2016, 2015 and 2014.~~2017. Under a practical expedient permitted by the standard, Xcel Energy used benefit cost amounts disclosed for prior periods as the basis for retrospective application.


3.	Selected Balance Sheet Data


(Thousands of Dollars)	June 30, 2017			Dec. 31, 2016
(Millions of Dollars)							March 31, 2018			Dec. 31, 2017
Accounts receivable, net
Accounts receivable	$	808,705		$	827,112		$	921		$	849
Less allowance for bad debts	(49,327		)	(50,823		)	(53		)	(52		)
	$	759,378		$	776,289		$	868		$	797


(Thousands of Dollars)	June 30, 2017		Dec. 31, 2016
(Millions of Dollars)					March 31, 2018		Dec. 31, 2017
Inventories
Materials and supplies	$	321,426	$	312,430	$	311	$	311
Fuel	156,736		181,752		144		186
Natural gas	63,882		110,044		37		113
	$	542,044	$	604,226	$	492	$	610


(Thousands of Dollars)	June 30, 2017			Dec. 31, 2016
(Millions of Dollars)							March 31, 2018			Dec. 31, 2017
Property, plant and equipment, net
Electric plant	$	38,810,158		$	38,220,765		$	39,348		$	39,016
Natural gas plant	5,465,224			5,317,717			5,855			5,800
Common and other property	1,959,703			1,888,518			2,027			2,013
Plant to be retired ^(a)	17,820			31,839			11			11
Construction work in progress	1,571,362			1,373,380			2,339			2,087
Total property, plant and equipment	47,824,267			46,832,219			49,580			48,927
Less accumulated depreciation	(14,703,391		)	(14,381,603		)	(15,276		)	(15,000		)
Nuclear fuel	2,660,606			2,571,770			2,701			2,697
Less accumulated amortization	(2,237,639		)	(2,180,636		)	(2,326		)	(2,295		)
	$	33,543,843		$	32,841,750		$	34,679		$	34,329


^(a)	In the ~~second half~~third quarter of 2017, PSCo ~~expects to both~~ early ~~retire~~retired Valmont Unit 5 and ~~convert~~converted Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired in approximately 2025. Amounts are presented net of accumulated depreciation.

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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, ~~2016~~2017 appropriately represents, in all material respects, the current status of other income tax matters, and ~~are~~is incorporated herein by reference.

~~Federal Loss Carryback Claims~~ ~~— In 2012-2015, Xcel Energy identified certain expenses related to 2009, 2010, 2011, 2013, 2014 and 2015 that qualify for an extended carryback beyond~~

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Total income tax expense from operations differs from the ~~typical two-year carryback period. As a result of a higher~~amount computed by applying the statutory federal income tax rate ~~in prior years, Xcel Energy recognized a~~to income before income tax ~~benefit of approximately $5 million in 2015, $17 million in 2014, $12 million in 2013 and $15 million in 2012.~~expense. The following reconciles such differences:



	Three Months Ended March 31
	2018		2017
Federal statutory rate	21.0	%	35.0	%
State tax, net of federal tax effect	4.9	%	4.0	%
Increases (decreases) in tax from:
Wind production tax credits	(6.0	)	(4.0	)
Regulatory differences - ARAM^(a)	(5.8	)	(0.1	)
Regulatory differences - ARAM deferral ^(b)	5.4		—
Regulatory differences - other utility plant items	(1.0	)	(0.5	)
Other, net	(1.6	)	(1.5	)
Effective income tax rate	16.9	%	32.9	%


^(a)	The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers.


^(b)	As we receive direction from our regulatory commissions regarding the return of excess deferred taxes (to our customers resulting from the TCJA), the ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a corresponding reduction to revenue.

Federal Audits — Xcel Energy files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s ~~2009 through 2013~~ federal income tax returns ~~following extensions, expires in December 2017.~~expire as follows:



Tax Year(s)		Expiration
2009 - 2011		December 2018
2012 - 2013		October 2018
2014		September 2018
2015		September 2019
2016		September 2020

In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. The IRS ~~has~~ proposed an adjustment to the federal tax loss carryback claims ~~that would result~~and in ~~$14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through~~ 2015, ~~claims. In 2016~~ the IRS ~~audit team and Xcel Energy presented their cases~~forwarded the issue to the Office of ~~Appeals; however,~~Appeals (Appeals). In 2017, Xcel Energy and Appeals reached an agreement and the ~~outcome and timing~~benefit related to the agreed upon portions was recognized. As of ~~a resolution is uncertain.~~March 31, 2018, the case has been forwarded to the Joint Committee on Taxation.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the ~~second~~third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment ~~to tax year 2012~~ that ~~may~~would impact Xcel Energy’s net operating loss (NOL) and effective tax rate (ETR). After evaluating the proposed adjustment, Xcel Energy ~~is evaluating~~filed a protest with the ~~IRS’ proposal and~~IRS. Xcel Energy anticipates the issue will be forwarded to Appeals. As of March 31, 2018, Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is ~~uncertain.~~unknown.

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State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. As of ~~June 30, 2017,~~March 31, 2018, 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		2012

In 2016, Minnesota began an audit of years 2010 through 2014. As of ~~June 30, 2017,~~March 31, 2018, Minnesota ~~had not proposed any adjustments;~~

~~In 2016, Texas began an audit of years 2009 and 2010. As of June 30, 2017, Texas~~ had not proposed any material adjustments;

In 2016, Wisconsin began an audit of years 2012 and 2013. As of ~~June 30, 2017,~~March 31, 2018, Wisconsin had not proposed any material adjustments; and

As of ~~June 30, 2017,~~March 31, 2018, there were no other state income tax audits in progress.

Unrecognized Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

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

(Millions of Dollars) June 30, 2017 Dec. 31, 2016
Unrecognized tax benefit — Permanent tax positions $ 30.8
$ 29.6
Unrecognized tax benefit — Temporary tax positions 106.6
104.1
Total unrecognized tax benefit $ 137.4
$ 133.7

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(Millions of Dollars)	March 31, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	21	$	20
Unrecognized tax benefit — Temporary tax positions	19		19
Total unrecognized tax benefit	$	40	$	39

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


(Millions of Dollars)	June 30, 2017			Dec. 31, 2016			March 31, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(47.4	)	$	(43.8	)	$	(32	)	$	(31	)

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 progresses and ~~audit progress,~~audits resume, the Minnesota ~~Texas~~ and Wisconsin audits progress, and other state audits resume. As the IRS Appeals and ~~IRS,~~ Minnesota ~~Texas~~ and Wisconsin audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately ~~$61~~$26 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. ~~A reconciliation of the beginning and ending amount of the payable~~The payables for interest related to unrecognized tax benefits ~~are as follows:~~

(Millions of Dollars) June 30, 2017 Dec. 31, 2016
Payable for interest related to unrecognized tax benefits at beginning of period $ (3.4 ) $ (0.1 )
Interest expense related to unrecognized tax benefits recorded during the period (1.7 ) (3.3 )
Payable for interest related to unrecognized tax benefits at end of period $ (5.1 ) $ (3.4 )

at March 31, 2018 and Dec. 31, 2017 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of ~~June 30, 2017~~March 31, 2018 or Dec. 31, ~~2016.~~2017.


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, ~~2016 and in Note 5 to Xcel Energy Inc.’s Quarterly Report on~~

~~Form 10-Q for the quarterly period ended March 31,~~ 2017, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

~~NSP-Minnesota~~

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~~Pending~~Tax Reform — Regulatory Proceedings

The specific impacts of the Tax Cuts and ~~Recently Concluded Regulatory Proceedings~~ Jobs Act (TCJA) on customer rates are subject to regulatory approval. Each of the states in Xcel Energy’s service areas have opened dockets to address the impacts of the TCJA. Xcel Energy has made filings and is working with various stakeholders in its jurisdictions to determine the appropriate treatment for the TCJA.

NSP-Minnesota — The Minnesota Public ~~Utilities~~Utility Commission (~~MPUC)~~ (MPUC) opened a TCJA docket and issued a request for information on the impacts of the TCJA in January 2018. In March 2018, the Minnesota Department of Commerce (DOC) recommended adjusting rates or implementing refunds for the current tax impacts and incorporating the deferred tax impacts in each utility’s next rate case.

In April 2018, NSP-Minnesota filed an update of the estimated impact of the TCJA, which reflected an overall reduction in 2018 revenue requirements of approximately $136 million for electric and $7 million for natural gas. The filing also proposed recommended options for delivering tax reform benefits to customers. The proposed electric options included: customer refunds and rider impacts of $68 million, deferral of $44 million to allow for a rate case stay-out for 2020, acceleration of depreciation for the King coal plant of $22 million and low income program funding of $2 million. The proposed natural gas options included customer refunds and rider impacts of $3 million, with the remaining TCJA benefits deferred to mitigate increased costs in the next natural gas rate case. A MPUC decision is expected later in 2018.

Dockets have also been opened in North Dakota and South Dakota. In February 2018, NSP-Minnesota proposed using the reduced revenue requirements from the TCJA to defer planned future rate filings in both jurisdictions.

~~Minnesota 2016 Multi-Year Electric Rate Case~~NSP-Wisconsin — In ~~June 2017,~~January 2018, the ~~MPUC~~Public Service Commission of Wisconsin (PSCW) issued an order requiring public utilities to apply deferred accounting for the impacts of the TCJA. In March 2018, NSP-Wisconsin filed recommended plans for Wisconsin, which for electric operations included an option for an immediate bill credit for a ~~written order. NSP-Minnesota estimates~~portion of the ~~total~~tax savings in 2018 and 2019, while deferring the remainder until NSP-Wisconsin’s 2020 electric rate ~~increase~~case. For the natural gas operations, NSP-Wisconsin proposed using the TCJA to ~~be approximately $245 million over~~reduce the ~~four-year period covering 2016-2019.~~unamortized regulatory asset for the Ashland/Northern States Power Lakefront Superfund Site (the Site) clean-up. A PSCW decision on the regulatory treatment of the TCJA is anticipated later in 2018.

~~Key terms:~~For Michigan, NSP-Wisconsin has reached settlement in its electric rate case, which reflects the impacts of the TCJA, and has proposed customer refunds for natural gas operations.

~~Four-year period covering 2016-2019;~~

~~Annual sales true-up;~~

~~Return on equity (ROE) of 9.2 percent~~PSCo — In January 2018, the Colorado Public Utilities Commission (CPUC) opened a statewide TCJA proceeding and ~~an equity ratio of 52.5 percent;~~

~~Nuclear related costs will not be considered provisional;~~

~~Continued use of~~ordered deferred accounting for all ~~existing riders, however no new riders may be utilized during the four-year term;~~

~~Deferral of incremental 2016 property tax expense above a fixed threshold to 2018 and 2019;~~

~~Four-year stay-out provision for rate cases;~~

~~Property tax true-up mechanism for 2017-2019; and~~

~~Capital expenditure true-up mechanism for 2016-2019.~~investor-owned utilities.

Colorado 2017 Multi-Year Natural Gas Rate Case- In February 2018, the administrative law judge (ALJ) approved PSCo and the CPUC Staff’s settlement agreement addressing the TCJA, which includes a $20 million reduction to provisional rates effective March 1, 2018. A final true-up, including any outcomes associated with the statewide proceeding, would provide customers the full net benefit of the TCJA effective January 2018. A CPUC decision is pending.

(Millions of Dollars, incremental) 2016 2017 2018 2019 Total
Revenues $ 74.99
$ 59.86
$ —
$ 50.12
$ 184.97
NSP-Minnesota’s sales true-up 59.95
—
—
(0.20 ) 59.75
Total rate impact $ 134.94
$ 59.86
$ —
$ 49.92
$ 244.72

Colorado Electric- In April 2018, PSCo, the CPUC Staff and the OCC filed a TCJA settlement agreement with the CPUC that identified a reduction in electric revenue requirements of approximately $101 million for the TCJA in 2018. The settlement recommended a customer refund of $42 million in 2018, with the remainder of $59 million be used to accelerate the amortization of an existing prepaid pension asset. With the dismissal of the 2017 rate case, revisions to the TCJA settlement are required to address the impacts of the TCJA for 2019 until new base rates go into effect in connection with a future electric rate case that PSCo anticipates filing later this summer. A CPUC decision is pending.

SPS — In January 2018, the Public Utility Commission of Texas (PUCT) issued an order requiring utilities to apply deferred accounting for the impacts of the TCJA. In February 2018, SPS filed with the PUCT supplemental testimony, which indicated that the TCJA would reduce revenue requirements by approximately $32 million and recommended increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. The impact of the TCJA is expected to be addressed as part of SPS’ pending Texas electric rate case, as discussed below.

In February 2018, SPS filed with the New Mexico Public Regulation Commission (NMPRC) a preliminary quantification of the impacts of the TCJA on its ongoing New Mexico 2017 electric rate case, which indicated that the TCJA would reduce revenue requirements by approximately $11 million and recommended increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. The impact of the TCJA is expected to be addressed as part of SPS’ pending New Mexico electric rate case, as discussed below.

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~~Annual Automatic Adjustment~~Federal Energy Regulatory Commission (FERC) Formula Rates — The FERC has not yet issued guidance on how or when electric utilities should reflect the impacts of ~~Fuel Clause Charges —~~ ~~In 2016,~~ the ~~Minnesota Department~~TCJA in FERC jurisdictional wholesale rates. The FERC issued a Notice of ~~Commerce (DOC) recommended~~Inquiry (NOI) in March 2018 seeking comments on how to reflect the ~~MPUC should hold utilities responsible for incremental costs of replacement power incurred due~~TCJA impacts in wholesale rates, in particular changes to ~~unplanned outages at nuclear facilities under certain circumstances. In May 2017, the MPUC voted to disallow approximately $4.4 million of replacement energy costs~~accumulated deferred income taxes and bonus depreciation. Comments for the ~~Prairie Island (PI) nuclear facility outages allocated~~NOI are due in May 2018. However, FERC-approved formula rates for wholesale customers are generally adjusted on an annual basis for certain changes in rate base and actual operating expenses, including income taxes. As a result, these revenues would be subject to an automatic reduction for the ~~Minnesota jurisdiction in 2015. This disallowance was recognized in~~effect of the ~~second quarter of 2017. The MPUC issued a written order in July 2017. In addition,~~TCJA corporate tax rate change through the ~~DOC is currently reviewing nuclear costs and operations under the initial rate case and resource plan orders as well as the recently finalized rate case.~~annual true-up process, absent specific FERC action.

NSP-Minnesota and NSP-Wisconsin were parties to a February 2018 FERC filing by certain transmission owner (TO) members of the Midcontinent Independent System Operator, Inc. (MISO) proposing to commence early reductions to transmission formula rates in 2018 for the corporate tax rate impacts of the TCJA. Also in February 2018, PSCo made a filing with FERC similarly requesting early reductions in its transmission and production formula rates in 2018 for corporate tax rate impacts of the TCJA. In March 2018, the FERC issued orders granting MISO TOs and PSCo’s waiver requests so that 2018 rates will reflect the lower federal corporate tax rate. For SPS, as a portion of the TCJA tax rate change largely offsets a depreciation rate change that was effective Jan. 1, 2018 in its wholesale production rates, SPS has notified FERC that it will continue to charge production rates established in 2017, subject to refund. SPS’ wholesale transmission rates continue to be calculated at the pre-TCJA corporate tax rate, subject to true-up in 2019.

NSP-Minnesota

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

~~Wisconsin~~GUIC Rider — In February 2018, ~~Electric and Natural Gas Rate Case~~— the MPUC approved a 2017 revenue requirement of approximately $20 million for GUIC investments. New rates went into effect in March 2018. In ~~May~~November 2017, ~~NSP-Wisconsin~~NSP-Minnesota filed the 2018 GUIC rider with the MPUC requesting recovery of approximately $28 million from Minnesota gas utility customers. In March 2018, NSP-Minnesota filed a ~~request~~supplement to the 2018 GUIC rider filing to provide an updated capital forecast and address the impact of the TCJA. The net result decreased NSP-Minnesota’s 2018 GUIC revenue requirement to approximately $24 million. The MPUC is currently considering the 2018 petition.

Renewable Energy Standard (RES) Rider — In 2017, NSP-Minnesota filed the 2017 and 2018 RES rider petition with the ~~PSCW to increase electric rates by $24.7~~MPUC, requesting approval of a 2017 over-recovery of approximately $10 million ~~or 3.6 percent,~~ and ~~natural gas rates by $12.0 million, or 10.1 percent, effective January 2018.~~a 2018 revenue requirement of approximately $11 million. The ~~rate filing is~~petition was based on a ~~2018 forecast test year, a ROE~~requested return on equity (ROE) of 10.0 percent ~~an equity ratio of 52.53 percent~~ and ~~a forecasted average net investment rate base of~~includes costs associated with the Courtenay wind farm and the 1,550 megawatt (MW) wind portfolio, which are offset by production tax credits (PTCs) and proceeds from renewable energy credit (REC) sales. The increase in revenue requirements in 2018 is due to new wind projects entering the construction phase. In February and March 2018, NSP-Minnesota filed supplements to the 2017 and 2018 RES rider petition to provide updated actual results and address TCJA impacts. NSP-Minnesota’s revised 2017 refund is approximately ~~$1.2 billion for~~$13 million, and the ~~electric utility and $138.4 million for~~revised 2018 revenue requirement is approximately $23 million. The increase in 2018 revenue requirements from the ~~natural gas utility.~~

~~Key dates~~original request is primarily driven by the TCJA impact on PTCs earned on existing wind asset-related costs. A decision from the MPUC is expected later in ~~the procedural schedule are as follows:~~

~~Staff and intervenor testimony — Sept. 12, 2017;~~

~~Rebuttal testimony — Sept. 26, 2017;~~

~~Sur-rebuttal testimony — Oct. 3, 2017; and~~

~~Hearing — Oct. 5, 2017.~~

~~A PSCW decision is anticipated in the fourth quarter of 2017.~~2018.

PSCo

Pending ~~and Recently Concluded~~ Regulatory Proceedings — ~~Colorado Public Utilities Commission (CPUC)~~CPUC

Colorado 2017 Multi-Year Electric Rate Case — In October 2017, PSCo filed a multi-year request with the CPUC seeking to increase electric rates approximately $245 million over four years. The request was based on forecast test years (FTY), a 10.0 percent ROE and an equity ratio of 55.25 percent. Interim rates, subject to refund and interest, were to be effective on June 1, 2018.



Revenue Request (Millions of Dollars)	2018		2019		2020		2021		Total
Revenue request	$	74	$	75	$	60	$	36	$	245
Clean Air Clean Jobs Act (CACJA) rider conversion to base rates	90		—		—		—		90
Transmission Cost Adjustment (TCA) rider conversion to base rates	43		—		—		—		43
Total	$	207	$	75	$	60	$	36	$	378

Expected year-end rate base (billions of dollars)	$	6.8	$	7.1	$	7.3	$	7.4

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In March 2018, PSCo, CPUC Staff and OCC reached a settlement and filed a motion with the CPUC requesting changes to the procedural schedule and scope of the electric case, which included delaying the implementation of provisional rates from June 2018 to January 2019 and requiring PSCo to file updated test year information for 2019-2021 which included the impacts of TCJA. In April 2018, the CPUC denied the motion on procedural grounds and dismissed the electric rate case. PSCo anticipates filing a new electric rate case in the summer of 2018 with new rates expected to be effective in the first quarter of 2019.

Colorado 2017 Multi-Year Natural Gas Rate Case — In June 2017, PSCo filed a multi-year request with the CPUC seeking to increase retail natural gas rates ~~to recover capital investments and increased operating costs since PSCo’s previous case in 2015.~~approximately $139 million over three years. The request, detailed below, is based on ~~forecast test years,~~FTYs, a 10.0 percent ROE and an equity ratio of 55.25 percent.

Revenue Request (Millions of Dollars) 2018 2019 2020 Total
New revenue request $ 63.2
$ 32.9
$ 42.9
$ 139.0
Pipeline System Integrity Adjustment (PSIA) revenue conversion to base rates ^(a)
—
93.9
—
93.9
Total $ 63.2
$ 126.8
$ 42.9
$ 232.9

Expected Year-End Rate Base (Billions of dollars) ^(b)
$ 1.5
$ 2.3
$ 2.4
N/A



Revenue Request (Millions of Dollars)	2018		2019		2020		Total
Revenue request	$	63	$	33	$	43	$	139
Pipeline System Integrity Adjustment (PSIA) rider conversion to base rates ^(a)	—		94		—		94
Total	$	63	$	127	$	43	$	233

Expected year-end rate base (billions of dollars) ^(b)	$	1.5	$	2.3	$	2.4


^(a)	The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request.


^(b)	The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider.

In October 2017, the CPUC Staff and the OCC recommended a single 2016 historic test year (HTY) based on an average 13-month rate base, and opposed a multi-year request. In addition, they recommended an equity ratio of 48.73 percent and 51.2 percent, respectively, and the existing PSIA rider expire with the 2018 rates rolled into base rates will not have an impact on customer bills or total revenue as these costs are already being recovered from customers through the rider. PSCo plans to request new PSIA rates for 2018 in November 2017. The recovery of new, incremental PSIA relatedbeginning Jan. 1, 2019. Planned investments in 2019 and 2020 ~~are included~~would be recoverable through a future rate case. The Staff and OCC provide for a recommended 2018 rate increase of approximately $30 million and $39 million, respectively.

Provisional rates, subject to refund, of $63 million were implemented on Jan. 1, 2018.

On Jan. 31, 2018, the CPUC ordered deferred accounting for the impacts of TCJA and opened a statewide TCJA proceeding, as discussed below. In February 2018, the ALJ approved a settlement agreement between PSCo and the CPUC, which reduced provisional rates by $20 million to address the impacts of the TCJA. The CPUC is expected to rule on the regulatory treatment of the TCJA and the natural gas rate case later in 2018.

On April 20, 2018, PSCo filed for a PSIA extension through 2020 in the event that the CPUC does not adopt its multi-year plan proposal.

SPS

Pending Regulatory Proceedings — PUCT

Texas 2017 Electric Rate Case — In 2017, SPS filed a $55 million, or 5.8 percent, retail electric, non-fuel base rate ~~request.~~increase case in Texas with each of its Texas municipalities and the PUCT. The request was based on a HTY ended June 30, 2017, a requested ROE of 10.25 percent, an electric rate base of approximately $1.9 billion and an equity ratio of 53.97 percent.

^(b)The ~~additional~~following table summarizes SPS’ rate ~~base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider.~~increase request:



Revenue Request (Millions of Dollars)
Incremental revenue request	$	69
Transmission Cost Recovery Factor (TCRF) rider conversion to base rates ^(a)	(14		)
Net revenue increase request	$	55

Final rates are expected to be effective in February 2018. In conjunction with the multi-year base rate step increases, PSCo is also proposing a stay-out provision and an earnings test through the end of 2020.

~~Annual Electric Earnings Test~~

^(a) — PSCo must share with customers earnings that exceed the authorized ROE of 9.83 percent for 2015 through 2017, as part of an annual earnings test. In July 2017, the CPUC approved PSCo’s 2016 earnings test, which does not result in any earnings sharing. The current estimate of the 2017 earnings test, based on annual forecasted information, did not result in the recognition of a liability as of June 30, 2017.

The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. SPS can request another TCRF rider after the conclusion of this rate case to recover transmission investments subsequent to June 30, 2017.

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~~SPS~~Key dates in the revised procedural schedule are as follows:

~~Pending~~PUCT Staff direct testimony — May 2, 2018;

PUCT Staff and ~~Recently Concluded Regulatory Proceedings~~intervenors’ cross-rebuttal testimony — ~~Public Utility Commission~~May 14, 2018;

SPS’ rebuttal testimony — May 23, 2018; and

Hearings — June 4 - 14, 2018.

As discussed above, the PUCT has opened a docket on the impact of ~~Texas (PUCT)~~the TCJA, which may have an impact on this rate case. In February 2018, SPS filed supplemental testimony with the PUCT, which indicated that TCJA would reduce revenue requirements by approximately $32 million and recommended increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. The final rates are expected to be effective retroactive to Jan. 23, 2018 through a customer surcharge. A PUCT decision is expected in the fourth quarter of 2018.

Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of ~~$42.1~~$42 million. In 2015, the PUCT approved an overall rate decrease of approximately ~~$4.0~~$4 million, net of rate case expenses. In April 2016, SPS filed an appeal with the Texas State District Court of(District Court) challenging the PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital structure, incentive compensation and wholesale load reductions. In ~~March~~ 2017, the ~~Travis County~~ District Court denied SPS’ ~~appeal. In April 2017,~~appeal, and SPS appealed the District Court’s decision to the Court of Appeals.

~~Texas 2016 Transmission Cost Recovery Factor (TCRF) Application~~ — In February 2017, SPS filed with the PUCT to recover additional annual revenue of approximately $16.1 million through its TCRF, or 1.8 percent. The filing was based upon capital transmission additions made during 2016. In June 2017, the PUCT approved TCRF rider recovery of approximately $14.4 million effective immediately. A decision is pending.

Pending Regulatory Proceeding — ~~New Mexico Public Regulation Commission (NMPRC)~~NMPRC

New Mexico 2017 Electric Rate Case — In October 2017, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base rates of approximately $43 million. The request is based on a HTY ended June 30, 2017, a ROE of 10.25 percent, an equity ratio of 53.97 percent and a rate base of approximately $885 million, including rate base additions through Nov. 30, 2017. This rate case also takes into account the decline in sales of 380 MW in 2017 from certain wholesale customers and seeks to adjust the life of SPS’ Tolk power plant (Unit 1 from 2042 to 2032 and Unit 2 from 2045 to 2032).

In February 2018, SPS filed supplemental information, which indicated that the TCJA would reduce revenue requirements by approximately $11 million. In addition, SPS requested an increase in the equity ratio of 58 percent and an adjustment to regional transmission revenue for the impacts of TCJA.

On April 13, 2018, the NMPRC Staff, the New Mexico Attorney General (NMAG), and several other parties filed testimony. The recommended ROE’s ranged from 9.0 percent to of 9.21 percent, and the recommended equity ratios were 51.0 percent to 53.97 percent.

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The following table summarizes certain parties’ recommendations from SPS’ request:



Millions of Dollars	NMPRC Staff Testimony				NMAG Testimony
SPS request	$	43			$	43
Reduction to request for the impact of the TCJA	(11		)		(11		)
SPS request, including the impact of the TCJA	32				32

ROE (9.0 percent and 9.21 percent, respectively)	(4		)		(6		)
Capital structure (52.0 percent and 53.97 percent, respectively)	(7		)		(3		)
Accelerated depreciation (Tolk plant)	(3		)		(3		)
Disallow rate case expenses	(2		)		(3		)
Regional transmission revenue (adjustment for the impact of the TCJA)	—			—	(3		)
Post test year plant (estimated numbers were updated to actual)	(1		)		(2		)
Other, net	(4		)		(5		)
Recommended rate increase	$	11			$	7

Key dates in the procedural schedule are as follows:

SPS’ rebuttal testimony — May 2, 2018; and

Hearings — May 15 - 25, 2018.

SPS anticipates a decision and implementation of final rates in the second half of 2018.

Appeal of the New Mexico 2016 Electric Rate Case Dismissal — In November 2016, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately ~~$41.4~~$41 million, representing a total revenue increase of approximately 10.9 percent. The rate filing iswas based on a requested ROE of 10.1 percent, an equity ratio of 53.97 percent, an electric rate base of approximately $832 million and a future test year ending June 30, 2018.

On April 10, 2017, the hearing examiner determined that SPS’ rate filing was deficient and recommended the NMPRC extend the procedural schedule by approximately one month and restart the suspension period once it is determined that the deficiencies are resolved. On April 19, In 2017, the NMPRC dismissed SPS’ rate case. ~~On May 15, 2017,~~ SPS filed a notice of appeal toin the New Mexico Supreme Court. A decision ~~from the New Mexico Supreme Court~~ is not expected until the second ~~or third quarter~~half of ~~2018.~~2019.

Pending Regulatory Proceeding — ~~Federal Energy Regulatory Commission (FERC)~~FERC

~~Midcontinent Independent System Operator, Inc. (MISO)~~MISO ROE Complaints — In November 2013, a group of customers filed a complaint at the FERC against MISO ~~transmission owners (TOs),~~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, and the removal of ROE adders (including those for Regional Transmission Organization (RTO) membership), effective Nov. 12, 2013.

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In ~~December 2015, an administrative law judge (ALJ) recommended~~September 2016, the FERC ~~approve~~approved an ALJ recommendation that MISO TOs be granted a base ROE of 10.32 percent for the MISO TOs. The ALJ found the existing 12.38 percent ROE to be unjust and unreasonable. The recommended 10.32 percent ROE applied a FERC ROE policy adopted in a June 2014 order (Opinion 531). The FERC approved the ALJ recommended 10.32 percent base ROE using the methodology adopted by FERC in ~~an order issued in September 2016.~~June 2014 (Opinion 531). This ROE would be applicable for the ~~15 month~~15-month refund period from Nov. 12, 2013 to Feb. 11, 2015, and prospectively from the date of the FERC order. The total prospective ROE would be 10.82 percent, including a 50 basis point adder for RTO membership. Various parties requested rehearing of the September 2016 order. The requests are pending FERC action.

In February 2015, a second complaint seeking to reduce the MISO ROE from 12.38 percent to 8.67 percent prior to any RTO adder was filed, ~~with the FERC,~~ resulting in a second period of potential ~~refund~~refunds from Feb. 12, 2015 to May 11, 2016. In June 2016, ~~the~~an ALJ recommended a base ROE of 9.7 percent, applying the ~~methodology adopted by~~FERC Opinion 531 methodology. Various parties filed exceptions to the ALJ recommendation, and FERC ~~in Opinion 531. A final FERC decision on the second ROE complaint was expected later in 2017, but in~~action is pending. In April 2017, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) ~~by opinion,~~ vacated and remanded Opinion 531. It is unclear how the D.C. Circuit’s opinion to vacate and remand Opinion 531 will affect the September 2016 FERC order or the timing and outcome of the second ROE complaint. ~~The MISO TOs are evaluating the impact of the D.C. Circuit ruling on the November 2013 and February 2015 ROE complaints.~~

~~As of June 30, 2017,~~ NSP-Minnesota has ~~processed the refunds for the Nov. 12, 2013 to Feb. 11, 2015 complaint period based on the 10.32 percent ROE provided in the September 2016 FERC order. NSP-Minnesota has also~~ recognized a current refund liability consistent with the best estimate of the final ROE for the Feb. 12, 2015 to May 11, 2016 complaint period.

~~Table~~Southwest Power Pool, Inc. (SPP) Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of ~~Contents~~participant-funded, or “sponsored,” transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP OATT has allowed SPP to charge for these upgrades since 2008, but SPP had not been charging its customers for these upgrades. In 2016, the FERC granted SPP’s request to recover the charges not billed since 2008. SPP subsequently billed SPS approximately $13 million for these charges. SPP is also billing SPS ongoing charges of approximately $0.5 million per month. SPS is currently seeking recovery of these SPP charges in its pending Texas and New Mexico base rate cases.

In October 2017, SPS filed a complaint against SPP regarding the amounts billed asserting that SPP has assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC denied SPS’ complaint. SPS sought rehearing in April 2018, which is pending FERC action. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings.


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, 2016, and in Notes 5 and 6 to the~~

~~consolidated financial statements included in Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended March~~ 31, 2017, 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.

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 3,537 ~~megawatts (MW)~~MW of capacity under long-term PPAs as of ~~June 30, 2017~~March 31, 2018 and Dec. 31, ~~2016,~~2017, 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 2041.

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 have a stated maximum guarantee or indemnity amount. As of ~~June 30, 2017~~March 31, 2018 and Dec. 31, ~~2016,~~2017, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.

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


(Millions of Dollars)	June 30, 2017		Dec. 31, 2016		March 31, 2018		Dec. 31, 2017
Guarantees issued and outstanding	$	18.3	$	18.8	$	18.6	$	18.8
Current exposure under these guarantees	—		0.1		—		—
Bonds with indemnity protection	49.4		43.0		51.7		53.1

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 future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.

Environmental Contingencies

Ashland Manufactured Gas Plant (MGP) Site — NSP-Wisconsin was 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 NSP-Wisconsin property, 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.

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In ~~2012,~~January 2017, NSP-Wisconsin agreed to remediate the Phase II Project Area (the Sediments), under a settlement agreement with the Environmental Protection Agency. The settlement agreements were approved by the U.S. District Court for the Western District of Wisconsin. NSP-Wisconsin initiated a full scale wet dredge remedy of the Sediments in 2017. Under the current plan, NSP-Wisconsin anticipates completion of restoration activities of the Sediments in 2018 with finalization of Phase I Project Area (which includes the Upper Bluff and Kreher Park areas of the Site)~~, under a settlement agreement with the United States Environmental Protection Agency (EPA).~~

~~NSP-Wisconsin performed a wet dredge pilot study in 2016~~ construction and demonstrated that a wet dredge remedy can meet the performance standards for remediation of the Phase II Project Area (the Sediments). As a result, the EPA authorized NSP-Wisconsin to extend the wet dredge pilot to additional areas of the Site. In January 2017, NSP-Wisconsin agreed to remediate the Sediments, under a settlement agreement with the EPA. The settlement was approved by the U.S. District Court for the Western District of Wisconsin. NSP-Wisconsin has initiated field activities to perform a full scale wet dredge remedy of the Sediments in 2017, with performance of restoration activities in ~~2018.~~early 2019 although April weather may challenge that schedule. Groundwater treatment activities at the Site will continue.

The current cost estimate for the remediation of the entire site (both Phase I Project Area and the Sediments) is approximately ~~$160.0~~$172 million, of which approximately ~~$113.2~~$139 million has been spent. ~~At June 30, 2017~~As of March 31, 2018 and Dec. 31, ~~2016,~~2017, NSP-Wisconsin had recorded a total liability of ~~$46.8~~$33 million and ~~$64.3~~$30 million, respectively, for the entire site.

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NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation costs as a regulatory asset. The PSCW has authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Site. In 2012, 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 ~~May~~December 2017, the PSCW approved an NSP-Wisconsin ~~filed a~~ natural gas rate case, which included recovery of additional expenses associated with remediating the Site. ~~If approved, the~~The annual recovery of MGP clean-up costs ~~would increase~~increased from ~~$12.4~~$12 million in 2017 to ~~$18.1~~$18 million in 2018.

Fargo, N.D. MGP Site — In May 2015, underground pipes, tars and impacted soils were discovered in a right-of-way in Fargo, N.D. that appeared to be associated with a former MGP operated by NSP-Minnesota or prior companies. NSP-Minnesota removed impacted soils and other materials ~~from the right-of-way~~ and commenced an investigation of the historic MGP and adjacent properties (the Fargo MGP Site). ~~NSP-Minnesota has recommended that targeted source removal of impacted soils and historic MGP infrastructure should be performed.~~ The North Dakota Department of Health approved NSP-Minnesota’s proposed cleanup plan in January ~~2017. The timing~~2017, which involves targeted source removal of impacted soils and ~~final scope of~~historic MGP infrastructure. It is anticipated that remediation ~~is dependent on whether reasonable access is provided to NSP-Minnesota to perform and implement the approved cleanup plan.~~activities will be performed in 2018. NSP-Minnesota has also 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 ~~September 2017.~~May 31, 2018.

~~As of June 30, 2017 and Dec. 31, 2016,~~ NSP-Minnesota had recorded aan estimated liability of ~~$16.4~~$15 million as of March 31, 2018 and ~~$11.3~~$16 million ~~respectively,~~as of Dec. 31, 2017, for the Fargo MGP Site. The current cost estimate for the remediation of the site is approximately ~~$23.0~~$22 million, of which approximately ~~$6.6~~$7 million has been spent. ~~In December 2015,~~NSP-Minnesota has deferred Fargo MGP Site costs allocable to the North Dakota jurisdiction, or approximately 88 percent of all remediation costs, as approved by the North Dakota Public Service Commission (NDPSC) ~~approved NSP-Minnesota’s~~. In December 2017, NSP-Minnesota filed a request with the MPUC to defer ~~costs associated with the Fargo~~post-2017 MGP ~~Site, resulting in deferral of all investigation and response costs with the exception of approximately 12 percent~~remediation expenditures allocable to the Minnesota ~~jurisdiction. Uncertainties related to~~jurisdiction, including the ~~liability recognized include obtaining access to perform~~Fargo MGP site. In March 2018, the ~~approved remediation (including~~DOC recommended that the prospective purchase of the historic MGP property), final designs that will be developed to implement the approved cleanup plan and the potential for contributions from entities that may be identified as PRPs.MPUC deny NSP-Minnesota’s deferral request. A MPUC decision is expected mid-2018.

Other MGP, ~~and~~ Landfill or Disposal Sites — Xcel Energy is currently involved in investigating and/or remediating several MGP, landfill or other ~~MGP and landfill~~disposal sites. Xcel Energy has identified ~~ten~~eleven sites across its service territories in addition to the sites in Ashland ~~Wis.~~ and Fargo, ~~N.D.,~~ where ~~former MGP or landfill disposal activities have or may have resulted in site~~ contamination is present and ~~are under current~~where investigation and/or ~~remediation. At some or all of these sites, there~~remediation activities are ~~other~~currently underway. Other parties ~~that~~ may have responsibility for some portion of ~~any remediation.~~the investigation and/or remediation activities. Xcel Energy anticipates that ~~the majority of the~~these investigation or remediation ~~at these sites~~activities will continue through at least 2018. Xcel Energy had accrued ~~$2.9~~$4 million ~~and $2.0 million for these sites at June 30, 2017~~as of March 31, 2018 and Dec. 31, ~~2016, respectively.~~2017 for all of these sites. There may be insurance recovery and/or recovery from other PRPs tothat will offset any costs incurred. Xcel Energy anticipates that any ~~significant~~ amounts ~~incurred~~spent will be fully recovered from customers.

~~Environmental Requirements~~

~~Water and Waste~~

~~Federal Clean Water Act (CWA) Waters of the United States Rule~~ —In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The final rule will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule. In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected by the end of 2017.

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In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. On June 27, 2017, the agencies issued a proposed rule that rescinds the 2015 final rule and reinstates the prior 1986 definition of “Water of the U.S.”

~~Air~~

~~Greenhouse Gas (GHG) Emission Standard for Existing Sources (Clean Power Plan or CPP)~~ — In 2015, the EPA issued its final rule for existing power plants. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets.

The CPP was challenged by multiple parties in the D.C. Circuit Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own.

In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate, publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA has requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. The D.C. Circuit granted the EPA’s request to hold the litigation in abeyance until June 27, 2017, and is considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, to determine whether and how the court continues or ends the stay that currently applies to the CPP. On June 9, 2017, the EPA submitted a proposed rule to the Office of Management and Budget entitled “Review of the Clean Power Plan.”

~~Regional Haze Rules~~ — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. The Best Available Retrofit Technology (BART) requirements of the EPA’s regional haze rules require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. Under BART, regional haze plans identify facilities that will have to reduce Sulfur Dioxide (SO₂₎, Nitrogen Oxide (NOx) and particulate matter emissions and set emission limits for those facilities. BART requirements can also be met through participation in interstate emission trading programs such as the Clean Air Interstate Rule (CAIR) and its successor, Cross-State Air Pollution Rule (CSAPR). The regional haze plans developed by Minnesota and Colorado have been fully approved and are being implemented in those states. States are required to revise their plans every ten years. The next plans for Minnesota and Colorado will be due in 2021. Texas’ first regional haze plan is still undergoing federal review as described below. President Trump’s Administration has not yet taken any public position regarding its views of the proposed and final regional haze regulations affecting SPS facilities in Texas.

~~Actions affecting Harrington Units:~~ Texas developed a State Implementation Plan (SIP) that finds the CAIR equal to BART for electric generating units. As a result, no additional controls beyond CAIR compliance would be required. In 2014, the EPA proposed to approve the BART portion of the SIP, with substitution of 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 under the D.C. Circuit Court’s remand of the Texas SO₂~~emission budgets. In June 2016, the EPA issued a memorandum which allows Texas to voluntarily adopt the CSAPR emission budgets limiting annual SO~~₂ and NOx emissions and rely on those emission budgets to satisfy Texas’ BART obligations under the regional haze rules. The Texas Commission on Environmental Quality has not utilized this option. The EPA then published a proposed rule in January 2017 that could have the effect of requiring installation of dry scrubbers to reduce SO₂ emissions from Harrington Units 1 and 2. Investment costs associated with dry scrubbers for Harrington Units 1 and 2 could be approximately $400 million. The EPA’s deadline to issue a final rule for Texas is September 2017.

~~Actions affecting Tolk units:~~ ~~In January 2016, the EPA adopted a final rule establishing a federal implementation plan for the state of Texas, which imposed SO~~₂ 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. SPS appealed the EPA’s decision and requested a stay of the final rule. The United States Court of Appeals for the Fifth Circuit (Fifth Circuit) granted the stay and decided that they are the appropriate venue for this case. In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, while leaving the stay in effect. The Fifth Circuit is now holding the case in abeyance until the EPA completes its reconsideration of the rule. It is likely that Texas and other affected entities including SPS would continue to challenge the determinations to date. The risk of these controls being imposed along with the risk of investments to provide cooling water to Tolk have caused SPS to seek to decrease the remaining depreciable life of the Tolk units.

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~~Revisions to the National Ambient Air Quality Standard (NAAQS) for Ozone~~ — In 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. In areas where Xcel Energy operates, current monitored air quality concentrations comply with the new standard in the Twin Cities Metropolitan Area in Minnesota and meet the 70 ppb level in the Texas panhandle. In documents issued with the new standard, the EPA projects that both areas will meet the new standard. The Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent standard, however PSCo’s scheduled retirement of coal fired plants in Denver that began in 2011 and will be completed in August 2017, should help in any plan to mitigate non-attainment. In June 2017, the EPA announced that it is delaying designations of nonattainment areas under the 2015 ozone NAAQS to October 2018 to allow it to complete its review of the 2015 ozone NAAQS.

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

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~~

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e prime, Xcel Energy Inc. and its other affiliates were sued along with several other gas marketing companies. These cases were all consolidated in the U.S. District Court in Nevada. ~~Five~~Six of the cases ~~have since been settled and seven~~ remain active, which includes ~~one~~a multi-district litigation (MDL) matter consisting of a Colorado class (Breckenridge), a Wisconsin class ~~(NSP-Wisconsin)~~(Arandell Corp.), a Missouri class, a Kansas class, and two other cases identified as “Sinclair Oil” and “Farmland.” In ~~November 2016,~~March 2017, summary judgment was granted by the MDL judge ~~dismissed e prime and~~in favor of Xcel Energy ~~from the Farmland lawsuit,~~ and Farmland has appealed the dismissal. Motions for summary judgment were filed by defendants, including e prime, in all of the remaining lawsuits. In March 2017, the U.S. District Court issued an order dismissing the claims against e prime in the Sinclair Oil ~~lawsuit~~ and ~~denied~~Farmland cases. In November 2017, the U.S District Court in Nevada granted summary judgment against two plaintiffs in the Arandell Corp. case in favor of Xcel Energy and NSP-Wisconsin, leaving only three individual plaintiffs remaining in the litigation. In addition, the plaintiffs’ motions for class certification and remand back to originating courts in these cases were denied in March 2017. Plaintiffs have appealed the ~~other lawsuits. The U.S. District Court did not grant e prime’s~~ summary judgment motions granted in the ~~Wisconsin or Colorado cases. There are currently additional motions brought by e prime~~Farmland and Sinclair Oil cases and the denial of class certification and remand to the U.S. Court of Appeals for ~~reconsideration~~the Ninth Circuit (Ninth Circuit). Oral arguments were heard before the Ninth Circuit in February 2018. In March 2018, the Ninth Circuit reversed and remanded the summary judgment ~~pending~~ in the ~~U.S. District Court.~~Farmland case. The Farmland defendants subsequently filed a request for further review by the Ninth Circuit. In light of the decision in the Farmland case, the Sinclair plaintiffs have requested the Ninth Circuit to reverse the grant of summary judgment without hearing. Final rulings on all pending motions and appeals are expected by the end of 2018. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote.

Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in the Denver ~~State~~District Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements entered into by PSCo and various developers. The dispute ~~involves~~involved claims by over fifty developers. In ~~May 2016,~~February 2018, the ~~district court granted PSCo’s motion~~Colorado Supreme Court denied DRC’s petition to ~~dismiss~~appeal the ~~lawsuit, concluding that jurisdiction over this dispute resides with the CPUC. In June 2016, DRC appealed the district court’s~~Denver District Court’s dismissal of the lawsuit, ~~and the Colorado Court of Appeals affirmed the lower court decision~~effectively terminating this litigation. However, in ~~favor of PSCo. In July 2017,~~January 2018, DRC filed a ~~petition~~new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to ~~appeal the decision~~file its line extension agreements with the ~~Colorado Supreme Court. It~~CPUC but failed to do so. This claim is ~~uncertain whether~~substantially similar to the ~~Colorado Supreme Court will grant the petition. DRC also brought~~arguments previously raised by DRC. In February 2018, PSCo filed a motion to dismiss. Dates for this proceeding before the CPUC as assignee on behalf of two developers, Ryland Homes and Richmond Homes of Colorado. In March 2016, the ALJ issued an order rejecting DRC’s claims for additional allowances and refunds. In June 2016, the ALJ’s determination was approved by the CPUC. DRC didhave not file a request for reconsideration before the CPUC contesting the decision, but filed an appeal in Denver District Court in August 2016. DRC has requested a hearing for oral arguments, which has yet to be granted or set by the Denver District Court.been scheduled.

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. The amount or range in dispute is presently unknown and no accrual has been recorded for this matter.

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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~~Short-Term Debt — 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.~~facilities and term loan agreements. Commercial paper and term loan borrowings outstanding for Xcel Energy ~~was~~were as follows:


(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2017			Year Ended Dec. 31, 2016			Three Months Ended March 31, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	2,750		$	2,750		$	3,250		$	3,250
Amount outstanding at period end	784			392			1,025			814
Average amount outstanding	778			485			1,000			644
Maximum amount outstanding	1,247			1,183			1,197			1,247
Weighted average interest rate, computed on a daily basis	1.28		%	0.74		%	1.93		%	1.35		%
Weighted average interest rate at period end	1.49			0.95			2.34			1.90

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Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At ~~June 30, 2017~~March 31, 2018 and Dec. 31, ~~2016,~~2017, there were ~~$14~~$31 million and ~~$19~~$30 million, respectively, 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.

~~At June 30, 2017,~~As of March 31, 2018, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available:


(Millions of Dollars)	Credit Facility ^(a)		Drawn ^(b)		Available		Credit Facility ^(a)		Drawn ^(b)		Available
Xcel Energy Inc.	$	1,000	$	549	$	451	$	1,500	$	898	$	602
PSCo	700		3		697		700		99		601
NSP-Minnesota	500		91		409		500		25		475
SPS	400		109		291		400		12		388
NSP-Wisconsin	150		46		104		150		22		128
Total	$	2,750	$	798	$	1,952	$	3,250	$	1,056	$	2,194


^(a)	These credit facilities expire in June ~~2021.~~2021, with the exception of Xcel Energy Inc.’s $500 million 364-day term loan agreement entered into in December 2017.


^(b)	Includes outstanding commercial paper, term loan borrowings and letters of credit.

All credit facility bank borrowings, outstanding letters of credit, term loan borrowings and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding ~~at June 30, 2017~~as of March 31, 2018 and Dec. 31, ~~2016.~~2017.

~~Long-Term Borrowings~~

~~PSCo issued $400 million of 3.80 percent first mortgage bonds due June 15, 2047.~~

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8.	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires 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 net asset value (NAV).

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Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled funds may be redeemed for NAV 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.

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 classification. 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 and SPS include transmission congestion instruments, generally referred to as financial transmission rights (FTRs). 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 transmission congestion. 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~~cleared prices for each FTR for the ~~historical pricing of FTR purchases.~~

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most recent auction.

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. ~~Fair~~Given the limited transparency in the auction process, fair value measurements for FTRs have been assigned a Level ~~3 given the limited observability of management’s forecasts for several of the inputs to this complex valuation model.~~3. Non-trading monthly FTR settlements 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, the ~~numerous unobservable quantitative inputs to~~limited transparency associated with the ~~complex model used for~~ valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy.

Non-Derivative Instruments Fair Value Measurements

Nuclear Decommissioning Fund

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 decommissioning the Monticello and PIPrairie Island (PI) nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other ~~investments – all classified as available-for-sale.~~investments. 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.

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Unrealized gains for the nuclear decommissioning fund were ~~$462.3~~$543 million and ~~$378.6~~$560 million ~~at June 30, 2017~~as of March 31, 2018 and Dec. 31, ~~2016,~~2017, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were ~~$34.2~~$18 million and ~~$46.9~~$7 million ~~at June 30, 2017~~as of March 31, 2018 and Dec. 31, ~~2016,~~2017, respectively.

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 June 30, 2017~~as of March 31, 2018 and Dec. 31, ~~2016:~~2017:


	June 30, 2017												March 31, 2018
			Fair Value												Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total
(Millions of Dollars)													Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	10,990	$	10,990	$	—	$	—	$	—	$	10,990	$	41	$	41	$	—	$	—	$	—	$	41
Commingled funds:
Non U.S. equities	280,608		191,881		—		—		106,085		297,966		270		226		—		—		90		316
Emerging market debt funds	96,008		—		—		—		103,736		103,736		157		—		—		—		164		164
Commodity funds	106,571		—		—		—		82,897		82,897
Private equity investments	138,889		—		—		—		195,491		195,491		142		—		—		—		198		198
Real estate	131,270		—		—		—		195,515		195,515		118		—		—		—		186		186
Other commingled funds	131,243		—		—		—		141,918		141,918		4		1		—		—		3		4
Debt securities:
Government securities	38,319		—		37,844		—		—		37,844		78		—		77		—		—		77
U.S. corporate bonds	141,510		—		142,330		—		—		142,330		325		—		321		—		—		321
Non U.S. corporate bonds	24,386		—		24,859		—		—		24,859		55		—		53		—		—		53
Equity securities:
U.S. equities	287,425		526,581		—		—		—		526,581		278		557		—		—		—		557
Non U.S. equities	171,695		226,868		—		—		—		226,868		153		229		—		—		—		229
Total	$	1,558,914	$	956,320	$	205,033	$	—	$	825,642	$	1,986,995	$	1,621	$	1,054	$	451	$	—	$	641	$	2,146


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes ~~$133.2~~$141 million of equity investments in unconsolidated subsidiaries and ~~$111.4~~$117 million of rabbi trust assets and miscellaneous investments.


^(b)	Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy.

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	Dec. 31, 2016												Dec. 31, 2017
			Fair Value												Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total
(Millions of Dollars)													Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	20,379	$	20,379	$	—	$	—	$	—	$	20,379	$	29	$	29	$	—	$	—	$	—	$	29
Commingled funds:
Non U.S. equities	260,877		133,126		—		—		112,233		245,359		264		217		—		—		90		307
Emerging market debt funds	93,597		—		—		—		97,543		97,543		156		—		—		—		166		166
Commodity funds	106,571		—		—		—		92,091		92,091
Private equity investments	132,190		—		—		—		190,462		190,462		141		—		—		—		198		198
Real estate	128,630		—		—		—		187,647		187,647		131		—		—		—		202		202
Other commingled funds	151,048		—		—		—		159,489		159,489		9		6		—		—		3		9
Debt securities:
Government securities	32,764		—		31,965		—		—		31,965		68		—		69		—		—		69
U.S. corporate bonds	104,913		—		105,772		—		—		105,772		320		—		322		—		—		322
Non U.S. corporate bonds	21,751		—		21,672		—		—		21,672		50		—		50		—		—		50
Municipal bonds	13,609		—		13,786		—		—		13,786
Mortgage-backed securities	2,785		—		2,816		—		—		2,816
Equity securities:
U.S. equities	270,779		473,400		—		—		—		473,400		271		557		—		—		—		557
Non U.S. equities	189,100		218,381		—		—		—		218,381		152		234		—		—		—		234
Total	$	1,528,993	$	845,286	$	176,011	$	—	$	839,465	$	1,860,762	$	1,591	$	1,043	$	441	$	—	$	659	$	2,143


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes ~~$132.8~~$140 million of equity investments in unconsolidated subsidiaries and ~~$98.3~~$114 million of rabbi trust assets and miscellaneous investments.


^(b)	Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy.

For the three ~~and six~~ months ended ~~June 30,~~March 31, 2018 and 2017 ~~and 2016~~ 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 June 30, 2017:~~as of March 31, 2018:


	Final Contractual Maturity										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
(Millions of Dollars)											Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Government securities	$	—	$	2,770	$	6,497	$	28,577	$	37,844	$	—	$	9	$	2	$	66	$	77
U.S. corporate bonds	2,824		44,843		78,518		16,145		142,330		3		87		174		57		321
Non U.S. corporate bonds	—		10,964		10,851		3,044		24,859		—		16		33		4		53
Debt securities	$	2,824	$	58,577	$	95,866	$	47,766	$	205,033	$	3	$	112	$	209	$	127	$	451

Rabbi Trusts

In ~~June~~ 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of its supplemental executive retirement plan and deferred compensation plan. The following tables present the cost and fair value of the assets held in rabbi trusts ~~at June 30, 2017~~as of March 31, 2018 and Dec. 31, ~~2016:~~2017:

June 30, 2017
Fair Value
(Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total
Rabbi Trusts ^(a)

Cash equivalents $ 11,214
$ 11,214
$ —
$ —
$ 11,214
Mutual funds 46,171
47,380
—
—
47,380
Total $ 57,385
$ 58,594
$ —
$ —
$ 58,594

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	March 31, 2018
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts ^(a)
Cash equivalents	$	11	$	11	$	—	$	—	$	11
Mutual funds	48		50		—		—		50
Total	$	59	$	61	$	—	$	—	$	61


	Dec. 31, 2016										Dec. 31, 2017
			Fair Value										Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
(Millions of Dollars)											Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts ^(a)
Cash equivalents	$	47,831	$	47,831	$	—	$	—	$	47,831	$	12	$	12	$	—	$	—	$	12
Mutual funds	1,663		1,901		—		—		1,901		47		50		—		—		50
Total	$	49,494	$	49,732	$	—	$	—	$	49,732	$	59	$	62	$	—	$	—	$	62


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

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 June 30, 2017,~~As of March 31, 2018, accumulated other comprehensive losses related to interest rate derivatives included ~~$3.0~~$3 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, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

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

~~At June 30, 2017,~~As of March 31, 2018, Xcel Energy had various vehicle fuel contracts designated as cash flow hedges extending through December 2018. Xcel Energy enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be 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 ~~and six~~ months ended ~~June 30, 2017~~March 31, 2018 and ~~2016.~~2017.

~~At June 30, 2017,~~As of March 31, 2018, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included immaterial ~~amounts~~net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

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

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The following table details the gross notional amounts of commodity forwards, options and FTRs ~~at June 30, 2017~~as of March 31, 2018 and Dec. 31, ~~2016:~~2017:


(Amounts in Thousands) ^(a)(b)	June 30, 2017	Dec. 31, 2016
(Amounts in Millions) ^(a)(b)			March 31, 2018	Dec. 31, 2017
Megawatt hours of electricity	101,225	46,773	60	68
Million British thermal units of natural gas	66,974	121,978	30	37
Gallons of vehicle fuel	360	—


^(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 ~~and six~~ months ended ~~June 30,~~March 31, 2018 and 2017 ~~and 2016,~~ on accumulated other comprehensive loss, regulatory assets and liabilities, and income:


	Three Months Ended June 30, 2017																Three Months Ended March 31, 2018
	Pre-Tax Fair Value Gains (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			Pre-Tax Fair Value Gains (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														Pre-Tax Gains Recognized During the Period in Income
Interest rate	$	—	$	—		$	1,319		^(a)	$	—			$	—
Vehicle fuel and other commodity	43		—			(5		)	^(b)	—				—
Total	$	43	$	—		$	1,314			$	—			$	—
(Millions of Dollars)																	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss		Regulatory Assets and (Liabilities)			Pre-Tax Gains (Losses) Recognized During the Period in Income
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—			$	5,785	^(c)	$	—	$	—		$	—	$	—			$	3		^(b)
Electric commodity	—		(1,299		)	—				(2,315		)	^(d)	—			—		(4		)	—		3		^(c)	—
Natural gas commodity	—		(1,685		)	—				—				—			—		1			—		2		^(d)	(2		)	^(d)
Total	$	—	$	(2,984	)	$	—			$	(2,315	)		$	5,785		$	—	$	(3	)	$	—	$	5		$	1

Six Months Ended June 30, 2017
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) 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 $ —
$ —
$ 2,678
^(a)
$ —
$ —

Vehicle fuel and other commodity 43
—
(5 )
^(b)
—
—

Total $ 43
$ —
$ 2,673
$ —
$ —

Other derivative instruments
Commodity trading $ —
$ —
$ —
$ —
$ 6,786
^(c)
Electric commodity —
(505 ) —
(6,313 )
^(d)
—

Natural gas commodity —
(7,846 ) —
1,075
^(e)
(4,070 )
^(e)
Total $ —
$ (8,351 ) $ —
$ (5,238 ) $ 2,716

Table of Contents


															Three Months Ended March 31, 2017
	Three Months Ended June 30, 2016														Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:							Pre-Tax Gains (Losses) Recognized During the Period in Income
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax 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)
(Millions of Dollars)															Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)					Pre-Tax Gains (Losses) Recognized During the Period in Income
Derivatives designated as cash flow hedges			��									Pre-Tax Gains Recognized During the Period in Income
Interest rate	$	—	$	—		$	1,483	^(a)	$	—		$	—		$	—	$	—		$	1	^(a)	$	—			$		—
Vehicle fuel and other commodity	19		—			47		^(b)	—			—
Total	$	19	$	—		$	1,530		$	—		$	—		$	—	$	—		$	1		$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—		$	481	^(c)	$	—	$	—		$	—		$	—			$	1		^(b)
Electric commodity	—		(705		)	—			16,642		^(d)	—			—		1			—			(4		)	^(c)	—
Natural gas commodity	—		6,063			—			—			25		^(e)	—		(6		)	—			1			^(d)	(4		)	^(d)
Total	$	—	$	5,358		$	—		$	16,642		$	506		$	—	$	(5	)	$	—		$	(3	)		$	(3	)

Six Months Ended June 30, 2016
Pre-Tax Fair Value Gains (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 $ —
$ —
$ 2,968
^(a)
$ —
$ —

Vehicle fuel and other commodity 13
—
104
^(b)
—
—

Total $ 13
$ —
$ 3,072
$ —
$ —

Other derivative instruments

Commodity trading $ —
$ —
$ —
$ —
$ 1,490
^(c)
Electric commodity —
(970 ) —
27,533
^(d)
—

Natural gas commodity —
3,361
—
11,666
^(e)
(4,999 )
^(e)
Total $ —
$ 2,391
$ —
$ 39,199
$ (3,509 )


^(a)	Amounts are recorded to interest charges.


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

^(e)(d)

Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Amounts for the three ~~and six~~ months ended ~~June 30,~~March 31, 2018 and 2017 included no$1 million of settlement ~~gains or~~ losses and $0.9 million of settlement gains, respectively. ~~Amounts for the three and six months ended June 30, 2016 included an immaterial amount of settlement losses.~~ The remaining derivative settlement gains and losses for the three ~~and six~~ months ended ~~June 30,~~March 31, 2018 and 2017 ~~and 2016~~ 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.

Xcel Energy had no derivative instruments designated as fair value hedges during the three ~~and six~~ months ended ~~June 30, 2017~~March 31, 2018 and ~~2016.~~2017. 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 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.

~~Table of Contents~~

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 June 30, 2017, two~~As of March 31, 2018, five of Xcel Energy’s 10 most significant counterparties for these activities, comprising ~~$28.1~~$70 million or 1235 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. ~~Eight~~Four of the 10 most significant counterparties, comprising ~~$75.7~~$27 million or 3214 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. ~~All ten~~The one remaining significant counterparty, comprising of $7 million or 4 percent of this credit exposure, had credit quality less than investment grade based on ratings from external 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 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~~subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies or for cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to ~~maintain its credit ratings. At June 30, 2017~~payment terms or other covenants. As of March 31, 2018 and Dec. 31, ~~2016,~~2017, there were no derivative instruments in a material liability position with such underlying contract ~~provisions that required the posting~~provisions.

Table of ~~collateral or settlement of applicable outstanding contracts if the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment grade.~~Contents

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 ~~June 30, 2017~~March 31, 2018 and Dec. 31, ~~2016.~~2017.

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 June 30, 2017:~~as of March 31, 2018:

June 30, 2017
Fair Value Fair Value Total
Counterparty Netting ^(b)
Total
(Thousands of Dollars) Level 1 Level 2 Level 3
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity $ —
$ 25
$ —
$ 25
$ (25 ) $ —
Other derivative instruments:
Commodity trading 2,974
13,383
2
16,359
(8,958 ) 7,401
Electric commodity —
—
68,069
68,069
(4,048 ) 64,021
Natural gas commodity —
1,439
—
1,439
—
1,439
Total current derivative assets $ 2,974
$ 14,847
$ 68,071
$ 85,892
$ (13,031 ) 72,861
PPAs ^(a)
5,626
Current derivative instruments $ 78,487
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity $ —
$ 14
$ —
$ 14
$ —
$ 14
Other derivative instruments:
Commodity trading 250
30,686
5,215
36,151
(7,307 ) 28,844
Total noncurrent derivative assets $ 250
$ 30,700
$ 5,215
$ 36,165
$ (7,307 ) 28,858
PPAs ^(a)
21,552
Noncurrent derivative instruments $ 50,410

~~Table of Contents~~



	March 31, 2018
	Fair Value						Fair Value Total		Counterparty Netting ^(b)			Total
(Millions of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	1	$	22	$	—	$	23	$	(12	)	$	11
Electric commodity	—		—		13		13		(2		)	11
Total current derivative assets	$	1	$	22	$	13	$	36	$	(14	)	22
PPAs ^(a)												6
Current derivative instruments												$	28
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	1	$	37	$	8	$	46	$	(15	)	$	31
Total noncurrent derivative assets	$	1	$	37	$	8	$	46	$	(15	)	31
PPAs ^(a)												18
Noncurrent derivative instruments												$	49


	June 30, 2017														March 31, 2018
	Fair Value						Fair Value Total		Counterparty Netting ^(b)			Total			Fair Value						Fair Value Total		Counterparty Netting ^(b)			Total
(Thousands of Dollars)	Level 1		Level 2		Level 3																Fair Value Total		Counterparty Netting ^(b)			Total
(Millions of Dollars)															Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative liabilities							Fair Value Total					Total											Counterparty Netting ^(b)
Derivatives designated as cash flow hedges:									Counterparty Netting ^(b)
Vehicle fuel and other commodity	$	—	$	—	$	—	$	—	$	(25	)	$	(25	)
Other derivative instruments:																					Fair Value Total
Commodity trading	3,050		11,443		1		14,494		(9,280		)	5,214			$	1	$	19	$	—	$	20	$	(13	)	Total	$	7
Electric commodity	—		—		4,048		4,048		(4,048		)	—			—		—		2		2		(1		)	1
Total current derivative liabilities	$	3,050	$	11,443	$	4,049	$	18,542	$	(13,353	)	5,189			$	1	$	19	$	2	$	22	$	(14	)	8
PPAs ^(a)												22,830														22
Current derivative instruments												$	28,019													$	30
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	98	$	22,861	$	—	$	22,959	$	(10,522	)	$	12,437		$	2	$	30	$	—	$	32	$	(19	)	$	13
Total noncurrent derivative liabilities	$	98	$	22,861	$	—	$	22,959	$	(10,522	)	12,437			$	2	$	30	$	—	$	32	$	(19	)	13
PPAs ^(a)												123,818														107
Noncurrent derivative instruments												$	136,255													$	120


^(a)	During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)

Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at ~~June 30, 2017.~~March 31, 2018. At ~~June 30, 2017,~~March 31, 2018, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of ~~$3.5~~$4 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

Table of Contents

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 atas of Dec. 31, ~~2016:~~2017:

Dec. 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 $ 13,179
$ 14,105
$ —
$ 27,284
$ (20,637 ) $ 6,647
Electric commodity —
—
19,251
19,251
(1,976 ) 17,275
Natural gas commodity —
8,839
—
8,839
—
8,839
Total current derivative assets $ 13,179
$ 22,944
$ 19,251
$ 55,374
$ (22,613 ) 32,761
PPAs ^(a)
5,463
Current derivative instruments $ 38,224
Noncurrent derivative assets
Other derivative instruments:

Commodity trading $ 100
$ 31,029
$ —
$ 31,129
$ (7,323 ) $ 23,806
Natural gas commodity —
1,652
—
1,652
—
1,652
Total noncurrent derivative assets $ 100
$ 32,681
$ —
$ 32,781
$ (7,323 ) 25,458
PPAs ^(a)
24,731
Noncurrent derivative instruments $ 50,189

~~Table of Contents~~



	Dec. 31, 2017
	Fair Value						Fair Value Total		Counterparty Netting ^(b)			Total
(Millions of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative assets
Other derivative instruments:
Commodity trading	$	2	$	22	$	—	$	24	$	(15	)	$	9
Electric commodity	—		—		32		32		(2		)	30
Total current derivative assets	$	2	$	22	$	32	$	56	$	(17	)	39
PPAs ^(a)												5
Current derivative instruments												$	44
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	31	$	5	$	36	$	(7	)	$	29
Total noncurrent derivative assets	$	—	$	31	$	5	$	36	$	(7	)	29
PPAs ^(a)												19
Noncurrent derivative instruments												$	48


	Dec. 31, 2016													Dec. 31, 2017
	Fair Value						Fair Value Total		Counterparty Netting ^(b)			Total		Fair Value						Fair Value Total		Counterparty Netting ^(b)			Total
(Thousands of Dollars)	Level 1		Level 2		Level 3															Fair Value Total		Counterparty Netting ^(b)			Total
(Millions of Dollars)														Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative liabilities							Fair Value Total					Total										Counterparty Netting ^(b)
Other derivative instruments:									Counterparty Netting ^(b)											Fair Value Total
Commodity trading	$	13,787	$	11,320	$	22	$	25,129	$	(20,974	)	$	4,155	$	2	$	18	$	—	$	20	$	(15	)	Total		$	5
Electric commodity	—		—		1,976		1,976		(1,976		)	—		—		—		2		2		(2		)	—
Natural gas commodity														—		1		—		1		—			1
Total current derivative liabilities	$	13,787	$	11,320	$	1,998	$	27,105	$	(22,950	)	4,155		$	2	$	19	$	2	$	23	$	(17	)	6
PPAs ^(a)												22,804													23
Current derivative instruments												$	26,959												$	29
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	89	$	23,424	$	—	$	23,513	$	(10,727	)	$	12,786	$	—	$	24	$	—	$	24	$	(10	)	$	14
Total noncurrent derivative liabilities	$	89	$	23,424	$	—	$	23,513	$	(10,727	)	12,786		$	—	$	24	$	—	$	24	$	(10	)	14
PPAs ^(a)												135,360													112
Noncurrent derivative instruments												$	148,146												$	126


^(a)	During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)

Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, ~~2016.~~2017. At Dec. 31, ~~2016,~~2017, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of ~~$3.7~~$3 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

Table of Contents

The following table presents the changes in Level 3 commodity derivatives for the three ~~and six~~ months ended ~~June 30, 2017~~March 31, 2018 and ~~2016:~~2017:

Three Months Ended June 30
(Thousands of Dollars) 2017 2016
Balance at April 1 $ 5,836
$ 6,854
Purchases 76,281
29,826
Settlements (22,272 ) (14,111 )
Net transactions recorded during the period:
Gains (losses) recognized in earnings ^(a)
6,016
(18 )
Net gains recognized as regulatory assets and liabilities 3,376
1,966
Balance at June 30 $ 69,237
$ 24,517

Six Months Ended June 30
(Thousands of Dollars) 2017 2016
Balance at Jan. 1 $ 17,253
$ 18,028
Purchases 80,073
31,670
Settlements (42,074 ) (26,161 )
Net transactions recorded during the period:
Gains (losses) recognized in earnings ^(a)
5,221
(43 )
Net gains recognized as regulatory assets and liabilities 8,764
1,023
Balance at June 30 $ 69,237
$ 24,517




	Three Months Ended March 31
(Millions of Dollars)	2018			2017
Balance at Jan. 1	$	35		$	17
Purchases	1			4
Settlements	(12		)	(20		)
Net transactions recorded during the period:
Gains recognized in earnings ^(a)	2			—
Net (losses) gains recognized as regulatory assets and liabilities	(7		)	5
Balance at March 31	$	19		$	6


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

Xcel Energy recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three ~~and six~~ months ended ~~June 30, 2017~~March 31, 2018 and ~~2016.~~2017.

~~Table of Contents~~

Fair Value of Long-Term Debt

As of ~~June 30, 2017~~March 31, 2018 and Dec. 31, ~~2016,~~2017, other financial instruments for which the carrying amount did not equal fair value were as follows:


	June 30, 2017				Dec. 31, 2016				March 31, 2018				Dec. 31, 2017
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(Millions of Dollars)									Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	14,597,178	$	15,879,594	$	14,450,247	$	15,513,209	$	14,979	$	15,877	$	14,976	$	16,531

The fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of ~~June 30, 2017~~March 31, 2018 and Dec. 31, ~~2016,~~2017, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.


9.	Other Income, Net

Other income, net consisted of the following:


	Three Months Ended June 30						Six Months Ended June 30						Three Months Ended March 31
(Thousands of Dollars)	2017			2016			2017			2016
(Millions of Dollars)													2018			2017
Interest income	$	2,107		$	984		$	5,907		$	5,054		$	5		$	4
Other nonoperating income	1,523			1,496			5,168			2,176			1			4
Benefits non-service cost													(5		)	(6		)
Insurance policy expense	(1,022		)	(920		)	(2,021		)	(1,420		)	—			(1		)
Other income, net	$	2,608		$	1,560		$	9,054		$	5,810		$	1		$	1


10.	Segment Information

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

Xcel Energy has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.

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

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

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

Xcel Energy had equity investments in unconsolidated subsidiaries of ~~$133.2~~$141 million and ~~$132.8~~$140 million as of ~~June 30, 2017~~March 31, 2018 and Dec. 31, ~~2016,~~2017, respectively, included in the regulated natural gas utility segment.

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

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

2928

Table of Contents


(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2017
(Millions of Dollars)													Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended March 31, 2018
Operating revenues from external customers	$	2,338,017	$	289,839	$	17,072		$	—		$	2,644,928	$	2,270	$	662	$	19		$	—		$	2,951
Intersegment revenues	433		285		—			(718		)	—		—		—		—			—			—
Total revenues	$	2,338,450	$	290,124	$	17,072		$	(718	)	$	2,644,928	$	2,270	$	662	$	19		$	—		$	2,951
Net income (loss)	$	227,562	$	13,166	$	(13,472	)	$	—		$	227,256	$	219	$	95	$	(22	)	$	(1	)	$	291


(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2016
(Millions of Dollars)													Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations		Consolidated Total
Three Months Ended March 31, 2017
Operating revenues from external customers	$	2,224,142	$	258,899	$	16,808		$	—		$	2,499,849	$	2,299	$	626	$	21		$	—	$	2,946
Intersegment revenues	421		241		—			(662		)	—		—		—		—			—		—
Total revenues	$	2,224,563	$	259,140	$	16,808		$	(662	)	$	2,499,849	$	2,299	$	626	$	21		$	—	$	2,946
Net income (loss)	$	205,440	$	11,933	$	(20,578	)	$	—		$	196,795	$	194	$	63	$	(18	)	$	—	$	239

(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total
Six Months Ended June 30, 2017
Operating revenues from external customers $ 4,637,077
$ 915,542
$ 38,731
$ —
$ 5,591,350
Intersegment revenues 730
549
—
(1,279 ) —
Total revenues $ 4,637,807
$ 916,091
$ 38,731
$ (1,279 ) $ 5,591,350
Net income (loss) $ 421,715
$ 76,093
$ (31,275 ) $ —
$ 466,533

(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total
Six Months Ended June 30, 2016
Operating revenues from external customers $ 4,409,261
$ 824,588
$ 38,273
$ —
$ 5,272,122
Intersegment revenues 756
528
—
(1,284 ) —
Total revenues $ 4,410,017
$ 825,116
$ 38,273
$ (1,284 ) $ 5,272,122
Net income (loss) $ 383,677
$ 90,271
$ (35,841 ) $ —
$ 438,107


11.	Earnings Per Share

Basic earnings per share (EPS) was computed by dividing the earnings available to Xcel Energy Inc.’s common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS was computed by dividing the earnings available to Xcel Energy Inc.’s common shareholders by the diluted weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method.

Common Stock Equivalents — Xcel Energy Inc. currently has common stock equivalents related to certain equity awards in share-based compensation arrangements.

Common stock equivalents causing a dilutive impact to EPS include commitments to issue common stock related to time based equity compensation awards.

Stock equivalent units granted to Xcel Energy Inc.’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these awards. Restricted stock, granted to settle amounts due to certain employees under the Xcel Energy Inc. Executive Annual Incentive Award Plan, is included in common shares outstanding when granted.

~~Table of Contents~~

Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following:

Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period.

Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement.

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The dilutive impact of common stock equivalents affecting EPS was as follows:


	Three Months Ended June 30, 2017					Three Months Ended June 30, 2016					Three Months Ended March 31, 2018					Three Months Ended March 31, 2017
(Amounts in thousands, except per share data)	Income		Shares	Per Share Amount		Income		Shares	Per Share Amount
(Amounts in millions, except per share data)											Income		Shares	Per Share Amount		Income		Shares	Per Share Amount
Net income	$	227,256	—	—		$	196,795	—	—		$	291	—	—		$	239	—	—
Basic EPS:
Earnings available to common shareholders	227,256		508,542	$	0.45	196,795		508,930	$	0.39	291		509.0	$	0.57	239		508.3	$	0.47
Effect of dilutive securities:
Time based equity awards	—		593	—		—		560	—
Equity awards											—		0.5	—		—		0.5	—
Diluted EPS:
Earnings available to common shareholders	$	227,256	509,135	$	0.45	$	196,795	509,490	$	0.39	$	291	509.5	$	0.57	$	239	508.8	$	0.47

Six Months Ended June 30, 2017 Six Months Ended June 30, 2016
(Amounts in thousands, except per share data) Income Shares Per Share
Amount Income Shares Per Share
Amount
Net income $ 466,533
—
—
$ 438,107
—
—
Basic EPS:

Earnings available to common shareholders 466,533
508,411
$ 0.92
438,107
508,789
$ 0.86
Effect of dilutive securities:

Time based equity awards —
544
—
—
522
—
Diluted EPS:

Earnings available to common shareholders $ 466,533
508,955
$ 0.92
$ 438,107
509,311
$ 0.86


12.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)


	Three Months Ended June 30												Three Months Ended March 31
	2017			2016			2017			2016			2018			2017			2018			2017
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
(Millions of Dollars)													Pension Benefits						Postretirement Health Care Benefits
Service cost	$	23,547		$	22,945		$	465		$	431		$	24		$	24		$	1		$	1
Interest cost(a)	36,702			40,028			5,984			6,526			33			36			5			6
Expected return on plan assets(a)	(52,318		)	(52,575		)	(6,155		)	(6,248		)	(52		)	(52		)	(6		)	(6		)
Amortization of prior service credit(a)	(442		)	(477		)	(2,672		)	(2,671		)	(1		)	—			(3		)	(3		)
Amortization of net loss(a)	26,671			24,385			1,672			1,009			27			26			2			1
Net periodic benefit cost (credit)	34,160			34,306			(706		)	(953		)	31			34			(1		)	(1		)
Costs not recognized due to the effects of regulation	(3,899		)	(4,159		)	—			—			—			(4		)	—			—
Net benefit cost (credit) recognized for financial reporting	$	30,261		$	30,147		$	(706	)	$	(953	)	$	31		$	30		$	(1	)	$	(1	)

~~Table of Contents~~

Six Months Ended June 30
2017 2016 2017 2016
(Thousands of Dollars) Pension Benefits Postretirement Health
Care Benefits
Service cost $ 47,094
$ 45,865
$ 930
$ 863
Interest cost 73,404
80,051
11,968
13,053
Expected return on plan assets (104,635 ) (105,150 ) (12,311 ) (12,497 )
Amortization of prior service credit (884 ) (961 ) (5,343 ) (5,343 )
Amortization of net loss 53,341
48,770
3,344
2,020
Net periodic benefit cost (credit) 68,320
68,575
(1,412 ) (1,904 )
Costs not recognized due to the effects of regulation (7,914 ) (8,611 ) —
—
Net benefit cost (credit) recognized for financial reporting $ 60,406
$ 59,964
$ (1,412 ) $ (1,904 )


^(a)	The components of net periodic cost other than the service cost component are included in the line item “other income, net” in the income statement or capitalized on the balance sheet as a regulatory asset.

In January ~~2017,~~2018, contributions of ~~$150.0~~$150 million were made across four of Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during ~~2017.~~2018.


13.	Other Comprehensive ~~Income~~Loss

Changes in accumulated other comprehensive ~~(loss) income,~~loss, net of tax, for the three ~~and six~~ months ended ~~June 30,~~March 31, 2018 and 2017 ~~and 2016~~ were as follows:

Three Months Ended June 30, 2017
(Thousands of Dollars)
Gains and Losses
on Cash Flow Hedges

Unrealized Gains and Losses
on Marketable Securities

Defined Benefit Pension and
Postretirement Items
Total
Accumulated other comprehensive (loss) income at April 1 $ (50,326 ) $ 110
$ (58,365 ) $ (108,581 )
Other comprehensive income before reclassifications 26
1
—
27
Losses reclassified from net accumulated other comprehensive loss 803
—
956
1,759
Net current period other comprehensive income 829
1
956
1,786
Accumulated other comprehensive (loss) income at June 30 $ (49,497 ) $ 111
$ (57,409 ) $ (106,795 )



	Three Months Ended March 31, 2018
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(58	)	$	(67	)	$	(125	)
Losses reclassified from net accumulated other comprehensive loss	—			1			1
Net current period other comprehensive income	—			1			1
Accumulated other comprehensive loss at March 31	$	(58	)	$	(66	)	$	(124	)

Three Months Ended June 30, 2016
(Thousands of Dollars)
Gains and Losses
on Cash Flow Hedges

Unrealized Gains and Losses
on Marketable Securities

Defined Benefit Pension and
Postretirement Items
Total
Accumulated other comprehensive (loss) income at April 1 $ (53,928 ) $ 110
$ (54,790 ) $ (108,608 )
Other comprehensive income before reclassifications 12
—
—
12
Losses reclassified from net accumulated other comprehensive loss 936
—
865
1,801
Net current period other comprehensive income 948
—
865
1,813
Accumulated other comprehensive (loss) income at June 30 $ (52,980 ) $ 110
$ (53,925 ) $ (106,795 )



	Three Months Ended March 31, 2017
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(51	)	$	(59	)	$	(110	)
Losses reclassified from net accumulated other comprehensive loss	1			1			2
Net current period other comprehensive income	1			1			2
Accumulated other comprehensive loss at March 31	$	(50	)	$	(58	)	$	(108	)

Six Months Ended June 30, 2017
(Thousands of Dollars)
Gains and Losses
on Cash Flow Hedges

Unrealized Gains
on Marketable Securities

Defined Benefit Pension and
Postretirement Items
Total
Accumulated other comprehensive (loss) income at Jan. 1 $ (51,151 ) $ 110
$ (59,313 ) $ (110,354 )
Other comprehensive income before reclassifications 26
1
—
27
Losses reclassified from net accumulated other comprehensive loss 1,628
—
1,904
3,532
Net current period other comprehensive income 1,654
1
1,904
3,559
Accumulated other comprehensive (loss) income at June 30 $ (49,497 ) $ 111
$ (57,409 ) $ (106,795 )

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Six Months Ended June 30, 2016
(Thousands of Dollars)
Gains and Losses
on Cash Flow Hedges

Unrealized Gains on Marketable Securities

Defined Benefit Pension and
Postretirement Items
Total
Accumulated other comprehensive (loss) income at Jan. 1 $ (54,862 ) $ 110
$ (55,001 ) $ (109,753 )
Other comprehensive income (loss) before reclassifications 8
—
(653 ) (645 )
Losses reclassified from net accumulated other comprehensive loss 1,874
—
1,729
3,603
Net current period other comprehensive income 1,882
—
1,076
2,958
Accumulated other comprehensive (loss) income at June 30 $ (52,980 ) $ 110
$ (53,925 ) $ (106,795 )

Reclassifications from accumulated other comprehensive loss for the three ~~and six~~ months ended ~~June 30,~~March 31, 2018 and 2017 ~~and 2016~~ were as follows:


(Thousands of Dollars)	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Millions of Dollars)									Amounts Reclassified from Accumulated Other Comprehensive Loss
	Three Months Ended June 30, 2017				Three Months Ended June 30, 2016				Three Months Ended March 31, 2018			Three Months Ended March 31, 2017
Losses (gains) on cash flow hedges:
Losses on cash flow hedges:
Interest rate derivatives	$	1,319		^(a)	$	1,483		^(a)	$	—	^(a)	$	1		^(a)
Vehicle fuel derivatives	(5		)	^(b)	47			^(b)
Total, pre-tax	1,314				1,530
Tax benefit	(511		)		(594		)
Total, net of tax	803				936				—			1
Defined benefit pension and postretirement losses:
Amortization of net loss	1,621			^(c)	1,478			^(c)	1		^(b)	2			^(b)
Prior service credit	(57		)	^(c)	(64		)	^(c)
Total, pre-tax	1,564				1,414				1			2
Tax benefit	(608		)		(549		)		—			(1		)
Total, net of tax	956				865				1			1
Total amounts reclassified, net of tax	$	1,759			$	1,801			$	1		$	2

Amounts Reclassified from Accumulated
Other Comprehensive Loss

(Thousands of Dollars) Six Months Ended June 30, 2017 Six Months Ended June 30, 2016
Losses (gains) on cash flow hedges:
Interest rate derivatives $ 2,678
^(a)
$ 2,968
^(a)
Vehicle fuel derivatives (5 )
^(b)
104
^(b)
Total, pre-tax 2,673
3,072

Tax benefit (1,045 ) (1,198 )
Total, net of tax 1,628
1,874

Defined benefit pension and postretirement losses:
Amortization of net loss 3,244
^(c)
2,956
^(c)
Prior service credit (117 )
^(c)
(128 )
^(c)
Total, pre-tax 3,127
2,828

Tax benefit (1,223 ) (1,099 )
Total, net of tax 1,904
1,729

Total amounts reclassified, net of tax $ 3,532
$ 3,603


^(a)	Included in interest ~~charges.~~charges


^(b)	~~Included in O&M expenses.~~


^(c)	Included in the computation of net periodic pension and postretirement benefit costs. See Note 12 for details regarding these benefit plans.

14. Revenues

Xcel Energy principally generates revenue from the transmission, distribution and sale of electricity and the transportation, distribution and sale of natural gas to wholesale and retail customers. Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. Xcel Energy recognizes revenue in an amount that corresponds directly to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. Contract terms are generally short-term in nature, and as such Xcel Energy does not recognize a separate financing component of its collections from customers. Xcel Energy presents its revenues net of any excise or other fiduciary-type taxes or fees.

NSP-Minnesota participates in MISO, and SPS participates in SPP. Xcel Energy’s utility subsidiaries recognize sales to both native load and other end use customers on a gross basis in electric revenue and cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges related to participating and transacting in RTOs are recorded on a net basis in cost of sales.

Xcel Energy Inc.’s utility subsidiaries have various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.

Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met (including collection within 24 months), revenue is recognized equal to the revenue requirement, which may include return on rate base items and incentives. The mechanisms are revised periodically for differences between the total amount collected and the revenue recognized, which may increase or decrease the level of revenue collected from customers. Alternative revenue is recorded on a gross basis and is disclosed separate from revenue from contracts with customers in the period earned.

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In the following tables, revenue is classified by the type of goods/services rendered and market/customer type. The tables also reconcile revenue to the reportable segments.



	Three Months Ended March 31, 2018
(Millions of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	687	$	390	$	9	$	1,086
Commercial and industrial (C&I)	1,112		207		7		1,326
Other	33		—		1		34
Total retail	1,832		597		17		2,446
Wholesale	188		—		—		188
Transmission	123		—		—		123
Other	39		28		—		67
Total revenue from contracts with customers	2,182		625		17		2,824
Alternative revenue and other	88		37		2		127
Total revenues	$	2,270	$	662	$	19	$	2,951



	Three Months Ended March 31, 2017
(Millions of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	685	$	374	$	8	$	1,067
C&I	1,148		195		9		1,352
Other	32		—		1		33
Total retail	1,865		569		18		2,452
Wholesale	181		—		—		181
Transmission	121		—		—		121
Other	25		25		—		50
Total revenue from contracts with customers	2,192		594		18		2,804
Alternative revenue and other	107		32		3		142
Total revenues	$	2,299	$	626	$	21	$	2,946

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

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

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Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including our ~~2017~~2018 earnings per share

guidance, the TCJA’s impact to Xcel Energy and its customers, long-term earnings per share and dividend growth rate, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” ~~“should”~~“should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, ~~2016,~~2017, and subsequent securities ~~filings,~~filings), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where Xcel Energy has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors including the extent and timing of the entry of additional competition in the markets served by Xcel ~~Energy and its subsidiaries;~~Energy; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability or cost of capital; and employee work force factors.

Non-GAAP Financial ~~Review~~Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as electric margin, natural gas margin, ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from the most directly comparable measure calculated and presented in accordance with GAAP. Xcel Energy’s management uses non-GAAP measures internally for financial planning and analysis, for reporting of results to the Board of Directors, in determining whether performance targets are met for performance-based compensation, and when communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our operating performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

Electric and Natural Gas Margins

Electric margin is presented as electric revenues less electric fuel and purchased power expenses and natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas sold and transported are generally recovered through various regulatory recovery mechanisms, and as a result, changes in these expenses are generally offset in operating revenues. Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales - other, O&M expenses, conservation and demand side management (DSM) expenses, depreciation and amortization and taxes (other than income taxes).

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Earnings Adjusted for Certain Items (Ongoing Earnings and Diluted EPS)

Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss attributable to the controlling interest of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. For the three months ended March 31, 2017 and 2018, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.

Results of Operations

The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. The diluted earnings and EPS of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole. ~~Ongoing~~

The following table summarizes GAAP and ongoing diluted EPS for Xcel ~~Energy~~Energy:



	Three Months Ended March 31
Diluted Earnings (Loss) Per Share	2018			2017
PSCo	$	0.26		$	0.22
NSP-Minnesota	0.22			0.19
SPS	0.07			0.05
NSP-Wisconsin	0.06			0.04
Equity earnings of unconsolidated subsidiaries	0.01			0.01
Regulated utility	0.62			0.51
Xcel Energy Inc. and other	(0.05		)	(0.04		)
Total	$	0.57		$	0.47

Summary of Earnings

Explanations below exclude the offsetting impacts on sales and income tax expense of the TCJA.

Xcel Energy— Xcel Energy’s earnings increased $0.10 per share for the first quarter of 2018. Increased electric and natural gas margins (excluding the impact of the TCJA), which reflect favorable weather compared to last year, timing of O&M expenses and an increased allowance for funds used during construction (AFUDC) were partially offset by ~~subsidiary is a financial measure not recognized under GAAP. Ongoing diluted EPS is calculated~~higher depreciation and interest expenses.

PSCo — Earnings increased $0.04 per share for the first quarter of 2018. The increase in earnings was driven by ~~dividing the net income or loss attributable~~higher natural gas margins (due to the ~~controlling interest~~impact of ~~each subsidiary, adjusted for certain~~an interim rate increase, subject to refund, and favorable weather) and increased AFUDC primarily related to the Rush Creek wind project. These items were partially offset by ~~the weighted average fully diluted Xcel Energy Inc. common shares outstanding~~higher depreciation expense.

NSP-Minnesota — Earnings increased $0.03 per share for the ~~period. We use this non-GAAP financial measure~~first quarter of 2018. The increase reflects lower O&M expenses and higher natural gas margins due to ~~evaluate~~favorable weather. These positive factors were partially offset by higher depreciation expense due to increased invested capital.

SPS — Earnings increased by $0.02 per share for the first quarter of 2018, largely due to timing of O&M expenses, the favorable impact of weather and ~~provide details~~lower interest expense.

NSP-Wisconsin — Earnings increased $0.02 per share for the first quarter of ~~Xcel Energy’s core earnings~~2018. The increase was driven by higher natural gas and ~~underlying performance. We believe this measurement is useful~~electric rates and the impact of favorable weather, partially offset by additional depreciation and amortization expense related to investors in facilitating period over period comparisons and evaluating or projecting financial results. This non-GAAP financial measure should not be considered as an alternative to measures calculated and reported in accordance with GAAP.higher invested capital.

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~~Results of Operations~~

~~The following table summarizes diluted EPS for Xcel Energy:~~

Three Months Ended June 30 Six Months Ended June 30
Diluted Earnings (Loss) Per Share 2017 2016 2017 2016
PSCo $ 0.20
$ 0.17
$ 0.42
$ 0.40
NSP-Minnesota 0.17
0.15
0.36
0.34
SPS 0.07
0.06
0.12
0.11
NSP-Wisconsin 0.03
0.02
0.07
0.06
Equity earnings of unconsolidated subsidiaries 0.01
0.01
0.02
0.03
Regulated utility ^(a)
0.48
0.42
0.99
0.93
Xcel Energy Inc. and other (0.03 ) (0.04 ) (0.07 ) (0.07 )
GAAP diluted EPS ^(a)
$ 0.45
$ 0.39
$ 0.92
$ 0.86


^(a)	~~Amounts may not add due to rounding.~~

~~Earnings Adjusted for Certain Items (Ongoing Earnings)~~

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

~~Summary of Earnings~~

~~Xcel Energy~~— Xcel Energy’s earnings increased $0.06 per share for the second quarter of 2017 and year-to-date. Earnings for the second quarter of 2017 increased due to higher electric and natural gas margins to recover infrastructure investments, along with a lower effective tax rate and lower operating and maintenance (O&M) expenses, partially offset by higher depreciation.

~~PSCo~~ — Earnings increased $0.03 per share for the second quarter of 2017 and $0.02 per share year-to-date. The year-to-date increase in earnings was driven by higher electric and natural gas margins and lower O&M expenses, partially offset by increased depreciation.

~~NSP-Minnesota~~ — Earnings increased $0.02 per share for the second quarter of 2017 and year-to-date. The year-to-date increase in earnings was due to higher electric margins driven by the rate case in Minnesota, as well as increased natural gas margins, non-fuel riders and lower O&M expenses, partially offset by increased depreciation.

~~SPS~~ — Earnings increased $0.01 per share for the second quarter of 2017 and year-to-date. The year-to-date increase in earnings was due to the positive impact of rate increases in Texas and New Mexico, which was partially offset by increased depreciation and timing of O&M expenses.

~~NSP-Wisconsin~~ — Earnings increased $0.01 per share for the second quarter of 2017 and year-to-date. The year-to-date increase in earnings was driven by higher electric margins primarily due to rate increases, which were partially offset by additional depreciation.

~~Table of Contents~~

~~Changes in~~Ongoing Diluted EPS

The following table summarizes significant components contributing to the changes in ~~2017~~2018 EPS compared with the same period in ~~2016:~~2017:

Diluted Earnings (Loss) Per Share Three Months Ended June 30 Six Months Ended June 30
2016 GAAP diluted EPS $ 0.39
$ 0.86

Components of change — 2017 vs. 2016
Higher electric margins 0.06
0.12
Lower ETR ^(a)
0.02
0.04
Higher natural gas margins 0.01
0.02
Lower O&M expenses 0.02
0.01
Higher depreciation and amortization (0.05 ) (0.11 )
Higher conservation and DSM expenses (offset by higher revenues) (0.01 ) (0.02 )
Other, net 0.01
—
2017 GAAP diluted EPS $ 0.45
$ 0.92



Diluted Earnings (Loss) Per Share	Three Months Ended March 31
GAAP and ongoing diluted EPS — 2017	$	0.47

Components of change — 2018 vs. 2017
Higher electric margins (excluding TCJA impacts)^(a)	0.04
Higher natural gas margins (excluding TCJA impacts)^(a)	0.04
Lower O&M expenses	0.03
Higher AFUDC — equity	0.02
Lower ETR (excluding TCJA impacts)^{(a) (b)}	0.01
Higher depreciation and amortization	(0.02		)
Higher interest charges	(0.01		)
Other, net	(0.01		)
GAAP and ongoing diluted EPS — 2018	$	0.57

^(a)TCJA impact:
Income tax - rate change	$	0.10
Electric revenue reductions	(0.08		)
Gas revenue reductions	(0.01		)
Holding company - interest expense	(0.01		)
Total	$	—


^(a)^(b)The ETR includes the impact of an additional $4 million of wind PTCs for the three months ended March 31, 2018, which are largely flowed back to customers through electric margin.	Lower ETR includes the impact of $4.8 million and $8.8 million of wind production tax credits (PTCs) for the three and six months ended June 30, 2017, respectively, which are largely flowed back to customers through electric margin.

Statement of Income Analysis

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

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

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

Normal weather conditions are defined as either the 20-year or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on ~~sales as defined above to derive the amount of demand associated with the weather impact.~~sales.

Table of Contents

There was no impact on sales for the first quarter of 2018 due to THI or CDD. The percentage increase (decrease) in normal and actual HDD ~~CDD and THI~~ is provided in the following table:

Three Months Ended June 30 Six Months Ended June 30
2017 vs.
Normal 2016 vs.
Normal 2017 vs.
2016 2017 vs.
Normal 2016 vs.
Normal 2017 vs.
2016
HDD (9.8 )% (3.7 )% (7.2 )% (8.5 )% (11.5 )% 2.3 %
CDD 5.4
1.7
3.7
7.4
1.7
5.5
THI (3.9 ) 15.8
(16.1 ) (6.9 ) 15.4
(21.4 )

~~Table of Contents~~



	Three Months Ended March 31
	2018 vs. Normal		2017 vs. Normal		2018 vs. 2017
HDD	0.3	%	(14.4	)%	16.0	%

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

Three Months Ended June 30 Six Months Ended June 30
2017 vs.
Normal 2016 vs.
Normal 2017 vs.
2016 2017 vs.
Normal 2016 vs.
Normal 2017 vs.
2016
Retail electric $ 0.005
$ 0.013
$ (0.008 ) $ (0.021 ) $ (0.004 ) $ (0.017 )
Firm natural gas (0.002 ) —
(0.002 ) (0.020 ) (0.013 ) (0.007 )
Total (excluding decoupling) $ 0.003
$ 0.013
$ (0.010 ) $ (0.041 ) $ (0.017 ) $ (0.024 )
Decoupling - Minnesota —
(0.007 ) 0.007
0.009
(0.001 ) 0.010
Total (adjusted for recovery from decoupling) $ 0.003
$ 0.006
$ (0.003 ) $ (0.032 ) $ (0.018 ) $ (0.014 )



	Three Months Ended March 31
	2018 vs. Normal			2017 vs. Normal			2018 vs. 2017
Retail electric	$	0.003		$	(0.025	)	$	0.028
Firm natural gas	0.003			(0.018		)	0.021
Total (before adjustments for decoupling)	$	0.006		$	(0.043	)	$	0.049
Decoupling – Minnesota	(0.002		)	0.008			(0.010		)
Total (adjusted for decoupling)	$	0.004		$	(0.035	)	$	0.039

Sales Growth (Decline) — The following tables summarize Xcel Energy and its subsidiaries’ sales growth (decline) for actual and weather-normalized sales in ~~2017~~2018 compared to the same period in ~~2016:~~2017:


	Three Months Ended June 30										Three Months Ended March 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential ^(a)	(1.5	)%	(1.4	)%	6.4	%	0.7	%	(0.3	)%	1.5	%	3.7	%	7.7	%	5.4	%	3.5	%
Electric commercial and industrial	2.6		(0.9	)	2.5		3.4		1.3		1.7		0.4		5.2		4.9		2.3
Total retail electric sales	1.4		(1.1	)	3.1		2.7		0.9		1.6		1.4		5.8		5.0		2.7
Firm natural gas sales	(8.5	)	3.6		N/A		4.2		(4.7	)	12.8		17.0		N/A		16.7		14.5

Three Months Ended June 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-normalized
Electric residential ^(a)
(0.3 )% 0.8 % 0.8 % 2.3 % 0.5 %
Electric commercial and industrial 3.0
(0.4 ) 2.3
3.7
1.5
Total retail electric sales 2.0
(0.1 ) 1.9
3.4
1.3
Firm natural gas sales (3.9 ) 4.6
N/A
3.3
(1.2 )

Six Months Ended June 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Actual
Electric residential ^(a)
(1.6 )% (1.2 )% (2.3 )% (0.5 )% (1.5 )%
Electric commercial and industrial 0.5
(1.0 ) 1.6
1.5
0.3
Total retail electric sales (0.1 ) (1.1 ) 0.8
0.8
(0.2 )
Firm natural gas sales (6.8 ) 4.0
N/A
3.7
(2.9 )

Six Months Ended June 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-normalized
Electric residential ^(a)
(0.6 )% 0.1 % (1.5 )% 0.9 % (0.3 )%
Electric commercial and industrial 0.7
(0.5 ) 1.4
1.6
0.5
Total retail electric sales 0.3
(0.4 ) 0.7
1.3
0.2
Firm natural gas sales (1.0 ) 4.2
N/A
3.3
0.9

~~Table of Contents~~


											Three Months Ended March 31
	Six Months Ended June 30 (Excluding Leap Day) ^(b)										PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized - adjusted for leap day
Weather-normalized
Electric residential ^(a)	—	%	0.7	%	(0.9	)%	1.5	%	0.3	%	(0.4	)%	(1.3	)%	1.2	%	(1.3	)%	(0.6	)%
Electric commercial and industrial	1.2		—		1.9		2.1		1.0		1.6		(0.6	)	4.9		4.3		1.8
Total retail electric sales	0.9		0.2		1.2		1.9		0.8		0.9		(0.8	)	4.3		2.5		1.1
Firm natural gas sales	(0.2	)	5.1		N/A		4.2		1.7		2.0		1.0		N/A		2.1		1.7


^(a)	Extreme weather variations, ~~and additional factors such as~~ windchill and cloud cover may not be reflected in weather-normalized and actual growth (decline) estimates.


^(b)	The estimated impact of the 2016 leap day is excluded to present a more comparable year-over-year presentation. The estimated impact of the additional day of sales in 2016 was approximately 50-60 basis points for retail electric and 80-90 basis points for firm natural gas for the six months ended.

Weather-normalized Electric Sales Growth (Decline) ~~— Year-To-Date Excluding Leap Day~~

PSCo’s ~~flat~~decline in residential sales ~~reflect an increased number of customers and~~reflects lower use per ~~customer. The commercial and industrial (C&I)~~customer, partially offset by customer additions. C&I growth was mainly due to an increase in ~~C&I~~ customers and higher use ~~per customer~~ for ~~both small and~~ large C&I ~~customers. The growth was primarily led by large~~ customers that support the metal mining ~~oil and gas industries.~~industries, which were partially reduced by lower use for the small C&I class.

NSP-Minnesota’s residential sales ~~growth reflects customer additions, partially offset by~~decrease was a result of lower use per ~~customer. Flat C&I sales resulted from lower sales to small customers,~~customer, partially offset by customer growth. ~~Increased~~The decline in C&I sales was largely due to reduced usage, which offset an increase in the number of customers. Declines in service related industries offset increased sales to large customers in the manufacturing and energy ~~industries offset smaller declines in services and air transportation.~~industries.

SPS’ residential ~~fell~~sales grew largely due to ~~lower use per customer. C&I sales growth reflects~~ higher use per customer and customer additions. The increase in C&I sales was driven by the oil and natural gas industry in the Permian Basin.

NSP-Wisconsin’s residential sales ~~increase~~decline was primarily attributable to ~~higher~~lower use per customer ~~and~~partially offset by customer additions. ~~The~~ C&I growth was largely due to ~~higher use per customer~~increased sales to small and ~~an increase in small customers in the~~large sand mining ~~industry.~~and energy industry customers.

Table of Contents

Weather-normalized Natural Gas Sales Growth ~~(Decline) - Year-To-Date Excluding Leap Day~~

Across most ~~natural gas~~ service territories, higher natural gas sales reflect an increase in the number of customers ~~partially offset by a decline in~~combined with increasing customer use.

Electric Revenues and Margin

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

Three Months Ended June 30 Six Months Ended June 30
(Millions of Dollars) 2017 2016 2017 2016
Electric revenues $ 2,338
$ 2,224
$ 4,637
$ 4,409
Electric fuel and purchased power (919 ) (856 ) (1,844 ) (1,718 )
Electric margin $ 1,419
$ 1,368
$ 2,793
$ 2,691

~~Table of Contents~~



	Three Months Ended March 31
(Millions of Dollars)	2018			2017
Electric revenues	$	2,333		$	2,299
Electric fuel and purchased power	(932		)	(925		)
Electric margin before impact of the TCJA	$	1,401		$	1,374
Impact of the TCJA (offset as a reduction in income tax expense)	(63		)	—
Electric margin	$	1,338		$	1,374

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

Electric Revenues

(Millions of Dollars) Three Months Ended June 30
2017 vs. 2016 Six Months Ended June 30
2017 vs. 2016
Retail rate increases (Texas, Minnesota, New Mexico and Wisconsin) $ 34
$ 75
Fuel and purchased power cost recovery 41
56
Trading 14
42
Non-fuel riders 9
20
Higher conservation and DSM revenues (offset by higher expenses) 7
14
Wholesale transmission revenue 1
12
Retail sales growth, excluding weather impact 8
9
Decoupling (weather portion - Minnesota) 5
7
Estimated impact of weather (6 ) (13 )
Other, net 1
6
Total increase in electric revenues $ 114
$ 228



(Millions of Dollars)	Three Months Ended March 31, 2018 vs. 2017
Fuel and purchased power cost recovery	$	(12	)
Firm wholesale	(7		)
Trading	21
Estimated impact of weather, net of Minnesota decoupling	15
Retail rate increase (Wisconsin)	5
Other, net	12
Total increase in electric revenues before impact of the TCJA	$	34
Impact of the TCJA (offset as a reduction in income tax expense)	(63		)
Total decrease in electric revenues	$	(29	)

Electric Margin

(Millions of Dollars) Three Months Ended June 30
2017 vs. 2016 Six Months Ended June 30
2017 vs. 2016
Retail rate increases (Texas, Minnesota, New Mexico and Wisconsin) $ 34
$ 75
Non-fuel riders 9
20
Higher conservation and DSM revenues (offset by higher expenses) 7
14
Retail sales growth, excluding weather impact 8
9
Decoupling (weather portion - Minnesota) 5
7
Wholesale transmission revenue, net of costs (6 ) (13 )
Estimated impact of weather (6 ) (13 )
Other, net
—
3
Total increase in electric margin $ 51
$ 102



(Millions of Dollars)	Three Months Ended March 31, 2018 vs. 2017
Firm wholesale	$	(7	)
Estimated impact of weather, net of Minnesota decoupling	15
Purchased capacity costs	11
Retail rate increase (Wisconsin)	5
Other, net	3
Total increase in electric margin before impact of the TCJA	$	27
Impact of the TCJA (offset as a reduction in income tax expense)	(63		)
Total decrease in electric margin	$	(36	)

Table of Contents

Natural Gas Revenues and Margin

Total natural gas expense ~~tends to vary~~varies with changing sales ~~requirements~~ and the cost of natural ~~gas purchases.~~gas. However, ~~due to the design of purchased natural gas cost recovery mechanisms for sales to retail customers,~~ fluctuations in the cost of natural gas has minimal impact on natural gas ~~margin.~~margin due to natural gas cost recovery mechanisms. The following table details natural gas revenues and margin:

Three Months Ended June 30 Six Months Ended June 30
(Millions of Dollars) 2017 2016 2017 2016
Natural gas revenues $ 290
$ 259
$ 916
$ 825
Cost of natural gas sold and transported (114 ) (90 ) (479 ) (402 )
Natural gas margin $ 176
$ 169
$ 437
$ 423

~~Table of Contents~~



	Three Months Ended March 31
(Millions of Dollars)	2018			2017
Natural gas revenues	$	673		$	626
Cost of natural gas sold and transported	(375		)	(365		)
Natural gas margin before impact of the TCJA	$	298		$	261
Impact of the TCJA (offset as a reduction in income tax expense)	(11		)	$	—
Natural gas margin	$	287		$	261

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

Natural Gas Revenues


(Millions of Dollars)	Three Months Ended June 30 2017 vs. 2016			Six Months Ended June 30 2017 vs. 2016			Three Months Ended March 31, 2018 vs. 2017
Estimated impact of weather							$	15
Retail rate increase (Colorado - interim, subject to refund, Wisconsin and Michigan)							12
Purchased natural gas adjustment clause recovery	$	23		$	76		9
Infrastructure and integrity riders	5			12			4
Higher conservation and DSM revenues (offset by higher expenses)	1			4
Estimated impact of weather	(1		)	(5		)
Sales growth							2
Other, net	3			4			5
Total increase in natural gas revenues before impact of the TCJA							$	47
Impact of the TCJA (offset as a reduction in income tax expense)							(11		)
Total increase in natural gas revenues	$	31		$	91		$	36

Natural Gas Margin


(Millions of Dollars)	Three Months Ended June 30 2017 vs. 2016			Six Months Ended June 30 2017 vs. 2016			Three Months Ended March 31, 2018 vs. 2017
Estimated impact of weather							$	15
Retail rate increase (Colorado - interim, subject to refund, Wisconsin and Michigan)							12
Infrastructure and integrity riders	$	5		$	12		4
Higher conservation and DSM revenues (offset by higher expenses)	1			4
Estimated impact of weather	(1		)	(5		)
Sales growth							2
Other, net	2			3			4
Total increase in natural gas margin before impact of the TCJA							$	37
Impact of the TCJA (offset as a reduction in income tax expense)							(11		)
Total increase in natural gas margin	$	7		$	14		$	26

Table of Contents

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses decreased ~~$18.8~~$23 million, or ~~3.2~~4.0 percent, for the ~~second~~first quarter of ~~2017~~2018, largely reflecting expense timing. The significant changes are summarized in the table below:



(Millions of Dollars)	Three Months Ended March 31, 2018 vs. 2017
Nuclear plant operations and amortization	$	(10	)
Plant generation costs	(9		)
Other, net	(4		)
Total decrease in O&M expenses	$	(23	)

Nuclear plant operations and amortization expenses are lower largely reflecting expense timing, savings initiatives and reduced refueling outage costs.

Plant generation costs decreased ~~$9.8 million, or 0.8 percent, year-to-date. The year-to-date decrease is~~ primarily due to the timing of planned maintenance and overhauls at a number of generation facilities, offset by increases in employee benefits expense and the impact of previously deferred 2016 expenses associated with the Texas 2016 electric rate case (approximately $8 million) recognized in 2017 in connection with the settlement, offset by revenue recovery.facilities.

Conservation and DSM Expenses — Conservation and ~~demand side management (DSM)~~DSM expenses increased ~~$8.9~~$3 million, or ~~16.0~~4.4 percent, for the ~~second~~first quarter of ~~2017 and increased $19.0 million, or 16.8 percent, year-to-date. Increases were~~2018. The increase was primarily due to higher recovery rates for Colorado electric and ~~additional customer~~natural gas sales. Increased participation in ~~electric~~Minnesota natural gas conservation programs ~~mostly in Minnesota.~~was partially offset by lower recovery rates. Conservation and DSM expenses are generally recovered in our major jurisdictions concurrently through riders and base rates. Timing of recovery may not correspond to the period in which costs were incurred.

Depreciation and Amortization — Depreciation and amortization increased ~~$43.2~~$18 million, or ~~13.4~~4.9 percent for the ~~second~~first quarter of ~~2017 and~~2018. The increase was primarily driven by capital expenditures due to planned system investments.

Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased ~~$88.4~~$3 million, or ~~13.8~~2.1 percent ~~year-to-date.~~for the first quarter of 2018. The increase was primarily due to ~~capital investments and prior year amortization of the excess depreciation reserve~~higher property taxes in ~~Minnesota.~~Colorado.

~~Allowance for Funds Used During Construction (AFUDC),~~AFUDC, Equity and Debt — AFUDC increased ~~$2.6~~$13 million for the ~~second~~first quarter of ~~2017 and increased $4.8 million year-to-date.~~2018. The increase was primarily due to ~~higher average capital investments, particularly~~ the Rush Creek wind ~~project.~~project in Colorado and other capital investments.

Interest Charges — Interest charges increased ~~$1.2~~$5 million, or ~~0.7~~3.0 percent, for the ~~second~~first quarter of ~~2017 and increased $10.7 million, or 3.4 percent, year-to-date.~~2018. The increase was related to higher debt levels to fund capital investments, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense decreased ~~$2.0~~$58 million for the ~~second~~first quarter of ~~2017~~2018 compared with the same period in ~~2016.~~2017. The decrease was primarily driven by a lower federal tax rate due to the TCJA, an increase in wind PTCs, ~~in 2017,~~ an increase in ~~permanent~~ plant-related ~~adjustments (e.g., AFUDC-equity)~~regulatory differences related to ARAM and an increase in ~~2017 and a~~other tax ~~expense for a state tax credit valuation allowance in 2016,~~credits. This was partially offset by ~~higher pretax earnings in~~ the ~~second quarter~~deferral of ~~2017.~~ARAM. The ETR was ~~31.1~~16.9 percent for the ~~second~~first quarter of ~~2017~~2018 compared with ~~34.7~~32.9 percent for the same period in ~~2016.~~2017. The lower ETR in ~~2017 was~~2018 is primarily due to the ~~adjustments~~items referenced above. See Note 4.

~~Table of Contents~~

Income tax expense decreased $14.0 million for the first six months of 2017 compared with the same period in 2016. The decrease in income tax expense was primarily due to an increase in wind PTCs in 2017, an increase in permanent plant-related adjustments (e.g., AFUDC-equity) in 2017 and a tax expense for a state tax credit valuation allowance in 2016, partially offset by higher pretax earnings in the six months ended June 30, 2017. The ETR was 32.0 percent for the first six months of 2017, compared to 34.7 percent for the first six months of 2016. The lower ETR in 2017 was primarily due to the adjustments referenced above.

Public Utility Regulation

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 1 of Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2016 and Public Utility Regulation included in Item 2 of Xcel Energy Inc.’s~~

~~Quarterly Report on Form 10-Q for the quarterly period ended March 31,~~ 2017 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

~~Xcel~~

Table of Contents

NSP-Minnesota

PPA Terminations and Amendments — In 2017, NSP-Minnesota filed requests with the MPUC and NDPSC to terminate or amend various PPAs to reduce future costs for customers, which are anticipated to result in excess of $600 million in net cost savings to NSP System customers over the next 10 years. In January 2018, the MPUC issued an order approving NSP-Minnesota’s petition to terminate the PPAs with Benson Power LLC (Benson) and Laurentian Energy ~~Inc.~~Authority I, LLC (Laurentian), as well as purchase and close the Benson biomass facility. In March 2018, the MPUC denied requests by several parties to reconsider its approval to terminate the Benson and Laurentian PPAs. NSP-Minnesota reached a settlement agreement with the NDPSC Staff which allows for the termination of the PPAs with Benson and Laurentian, as well as the purchase and closure of the Benson biomass facility. A NDPSC decision is anticipated in May 2018.

Wind Development —During the first quarter of 2017, Xcel Energy announced plans to significantly expand its wind capacity by adding 1,550 MW of new wind generation at NSP-Minnesota and 1,230 MW at SPS. Previously, Xcel Energy received regulatory approval to build a 600 MW wind farm at PSCo.

In ~~July~~ 2017, the MPUC approved NSP-Minnesota’s proposal to add 1,550 MW of new wind generation including ownership of 1,150 MW of wind generation. NSP-Minnesota plans to submit updates including TCJA impacts on the new wind generation ~~by NSP-Minnesota.~~to the MPUC and NDPSC in May 2018. The ~~MPUC approved an aggregate capital cap for~~timing of a NDPSC order is uncertain. The regulatory filing updates are not expected to impact the ~~750 MW~~timing of ~~self-build~~these projects ~~allowing NSP-Minnesota to include in rate base any savings versus a capital cost estimate for the projects. NSP-Minnesota would not recover capital costs in excess of the cap.~~

~~The PUCT and NMPRC~~which are expected to ~~rule on SPS’ wind projects~~be completed by the end of ~~the first quarter of 2018.~~

~~Key dates in the PUCT procedural schedule are as follows:~~

~~Intervenor testimony — Oct. 2, 2017;~~

~~Staff testimony — Oct. 9, 2017;~~

~~Rebuttal testimony — Oct. 23, 2017;~~2020 and

~~Hearing — Nov. 6 - Nov. 17, 2017.~~

~~Key dates in the NMPRC procedural schedule are as follows:~~

~~Staff and intervenor testimony — Oct. 24, 2017;~~

~~Rebuttal testimony — Nov. 9, 2017; and~~

~~Hearing — Nov. 28 - Dec. 1, 2017.~~

In total, Xcel Energy has proposed adding 3,380 MW of wind capacity by the end of 2020. Xcel Energy has filed to own and place in rate base 2,750 MW of these wind projects, while 630 MW would be through PPAs. These wind projects would qualify for 100 percent of the ~~production tax credit~~PTC. NSP-Minnesota’s total capital investment for these wind ownership projects is expected to be approximately $1.9 billion.

In 2017, NSP-Minnesota filed with the MPUC seeking approval to build and own the Dakota Range, a 300 MW wind project in South Dakota. The project is expected to be placed into service by the end of 2021 and qualify for 80 percent of the PTC. In March 2018, NSP-Minnesota submitted supplemental filings to the MPUC and NDPSC regarding the impacts of the TCJA and other updated information for Dakota Range. These impacts result in a minimal increase in the revenue requirement for Dakota Range and the project continues to show significant benefits to customers. In April 2018, the MPUC approved NSP-Minnesota’s petition to build and own the Dakota Range. A NDPSC decision is pending.

These wind projects are ~~intended~~expected to provide ~~billions of dollars of~~significant savings to ~~our~~NSP-Minnesota’s customers and substantial environmental benefits. Projected savings/benefits assume fuel costs and generation mix consistent with ~~those included in~~ various commission approved resource plans ~~and generation need filings.~~

~~Table of Contents~~

~~The following table details these wind projects:~~

Project Name Capacity (MW) State Estimated Year of Completion Ownership/PPA Regulatory Status
Rush Creek 600
CO 2018 PSCo Approved by CPUC
Freeborn 200
MN/IA 2020 NSP-Minnesota Approved by MPUC
Blazing Star 1 200
MN 2019 NSP-Minnesota Approved by MPUC
Blazing Star 2 200
MN 2020 NSP-Minnesota Approved by MPUC
Lake Benton 100
MN 2019 NSP-Minnesota Approved by MPUC
Foxtail 150
ND 2019 NSP-Minnesota Approved by MPUC
Crowned Ridge 300
SD 2019 NSP-Minnesota Approved by MPUC
Hale 478
TX 2019 SPS Pending PUCT & NMPRC Approval
Sagamore 522
NM 2020 SPS Pending PUCT & NMPRC Approval
Total Ownership 2,750

Crowned Ridge 300
SD 2019 PPA Approved by MPUC
Clean Energy 1 100
ND 2019 PPA Approved by MPUC
Bonita 230
TX 2019 PPA Pending PUCT & NMPRC Approval
Total PPA 630

~~Xcel Energy’s total capital investment for the proposed wind ownership projects is approximately $4.2 billion for 2017-2020.~~

~~NSP-Minnesota~~

~~PPA Terminations and Amendments~~Minnesota State Right-Of-First Refusal (ROFR) Statute Complaint — In ~~June~~September 2017, LSP Transmission Holdings, LLC (LSP Transmission) filed a complaint in the U.S. District Court for the District of Minnesota (Minnesota District Court) against the Minnesota Attorney General, the MPUC and ~~July 2017,~~the DOC. The complaint was in response to MISO assigning NSP-Minnesota and ITC Midwest, LLC to jointly own a new 345 KV transmission line from near Mankato, Minn. to Winnebago, Minn. The line was estimated by MISO to cost $103 million. The project was assigned to NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a Minnesota state ROFR statute. The complaint challenges the constitutionality of the state ROFR statute and is seeking declaratory judgment that the statute violates the Commerce Clause of the U.S. Constitution and should not be enforced. The Minnesota state agencies and NSP-Minnesota filed ~~requests with~~motions to dismiss. In April 2018, the ~~MPUC and/or~~Antitrust Division of the ~~NDPSC for several initiatives including changes to four PPAs to reduce future costs for customers. These actions include~~United States Department of Justice, filed a statement in support of LSP Transmission’s position that the ~~following:~~statute is unconstitutional. The matter is pending before the Minnesota District Court. The timing and outcome of the litigation is uncertain.

The termination of a PPA with Benson Power LLC (Benson) for its 55 MW biomass facility in Benson, Minn. The termination of the Benson PPA requires FERC approval and would result in payments of $95 million to terminate the PPA and acquire the facility, as well as additional expenditures of approximately $26 million to temporarily operate then close the facility.

The termination of a PPA with Laurentian Energy Authority I, LLC (Laurentian) for its 35 MW of biomass facilities in Hibbing and Virginia, Minn. The termination of the Laurentian PPA would result in $108.5 million of contract cancellation payments over six years.

The remaining two requested PPA changes involve a PPA extension for a 34 MW waste-to-energy facility at a price reflective of current market conditions and termination of another 12 MW waste-to-energy PPA.

NSP-Minnesota has requested recovery of all costs associated with these changes through the Fuel Clause Adjustment, including a return on NSP-Minnesota’s total investment in the Benson transaction over the remaining life of the current PPA through 2028. If approved, these actions together are intended to provide approximately $653 million in net cost savings to customers over the next 10 years.

Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the PI plant. See Note 1412 of ~~Xcel Energy Inc.’s~~NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2016~~2017 for further discussion regarding the nuclear generating plants. The circumstances set forth in Nuclear Power Operations and Waste Disposal included in Item 1 of ~~Xcel Energy Inc.’s~~NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. ~~31, 2016 and Nuclear Power Operations included in Item 2 of Xcel Energy Inc.’s Quarterly~~

~~Report on Form 10-Q for the quarterly period ended March~~ 31, 2017, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated herein by reference.

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NSP-Wisconsin

~~NSP-Wisconsin / American Transmission Company, LLC (ATC) - La Crosse to Madison, Wis. Transmission Line~~ — In 2013, NSP-Wisconsin and ATC jointly filed an application with the PSCW for a certificate of public convenience and necessity (CPCN) for a new 345 kilovolt transmission line that would extend from La Crosse, Wis. to Madison, Wis. NSP-Wisconsin’s half of the line will be shared with three co-owners, Dairyland Power Cooperative, WPPI Energy and Southern Minnesota Municipal Power Agency-Wisconsin.

In 2015, the PSCW issued its order approving a CPCN and route for the project. Two groups have appealed the CPCN order to the La Crosse County Circuit Court (Circuit Court). In May 2017, the Circuit Court determined that the project was necessary, allowing construction to continue on a seven mile segment near La Crosse, Wis. The parties have appealed various aspects of the case to the Wisconsin Court of Appeals, which is currently pending. The CPCN remains in full effect unless one of the parties seeks and receives a stay from the court and posts a bond to cover damages the utilities may incur due to delay. The 180-mile project is expected to cost approximately $541 million. NSP-Wisconsin’s portion of the investment, which includes AFUDC, is estimated to be approximately $200 million. Construction on the line began in January 2016, with completion anticipated by late 2018.

~~2016 Electric Fuel Cost Recovery~~ — NSP-Wisconsin’s electric fuel costs for the year ended Dec. 31, 2016 were lower than authorized in rates and outside the two percent annual tolerance band established in the Wisconsin fuel cost recovery rules, primarily due to lower sales volume and lower purchased power costs coupled with moderate weather. Under the fuel cost recovery rules, NSP-Wisconsin may retain the amount of over-recovery up to two percent of authorized annual fuel costs, or approximately $3.4 million. However, NSP-Wisconsin must defer the amount of over-recovery in excess of the two percent annual tolerance band for future refund to customers. In July 2017, the PSCW required NSP-Wisconsin to provide a refund of $9.5 million to customers, which is expected to start in September 2017.

2017 Electric Fuel Cost Recovery —NSP-Wisconsin’s electric fuel costs for ~~the six months ended June 30,~~ 2017 were lower than authorized in rates and outside the two percent annual tolerance band, ~~established in the Wisconsin fuel cost recovery rules,~~ primarily due to ~~lower sales volume and~~ lower purchased power costs coupled with moderate weather and generation sales into the MISO market. Under the fuel cost recovery rules, NSP-Wisconsin may retain ~~the amount~~approximately $4 million of ~~over-recovery up to two percent of authorized annual~~ fuel costs ~~or approximately $3.7 million. However, NSP-Wisconsin must~~and defer the amount of over-recovery in excess of the two percent annual tolerance band for future refund to customers. Accordingly, NSP-Wisconsin recorded a deferral of approximately $3.0 million through June 30, 2017. The amount of the deferral could increase or decrease based on actual fuel costs incurred for the remainder of the year. In ~~the first quarter of~~March 2018, NSP-Wisconsin ~~will file~~filed a reconciliation of 2017 fuel costs with the ~~PSCW.~~PSCW indicating a refund liability of approximately $10 million. The final amount of ~~any potential~~the refund is subject to review and approval by the PSCW, which is ~~not~~ expected ~~until mid-2018.~~

~~PSCo~~

~~Rush Creek Wind Ownership Proposal~~ ~~— In 2016, the CPUC granted PSCo a CPCN to build, own and operate a 600 MW wind generation facility~~ in Colorado at Rush Creek. The CPCN includes a hard cost-cap of $1.096 billion (including transmission costs) and a capital cost sharing mechanism between customers and PSCo of 82.5 percent to customers and 17.5 percent to PSCo for every $10 million the project comes in below the cost-cap.mid- 2018.

All major contracts required to complete the project have been executed including the Vestas turbine supply and balance of plant agreements. Vestas PTC components for safe harboring the facility have been fabricated and are currently being stored at Vestas facilities in Colorado. Construction of roads, collection systems, and foundations began in April 2017.

In June 2017, PSCo filed its report required under Colorado rules that require PSCo to consider Best Value Employment Metrics (BVEM) as a factor in selecting contractors for generation projects. On July 5, 2017, several building trades filed comments arguing that PSCo’s Balance of Plant Contractor selection was inappropriate as it did not follow a more detailed and quantitative analysis. The trade unions argued that the BVEM deficiencies could be remedied through execution of a Project Labor Agreement on the project. PSCo filed its reply indicating that it satisfied the BVEM rule requirements on July 18, 2017, which was discussed by the CPUC on July 20, 2017. The CPUC took no action other than to request reconsideration of whether bidder’s BVEM information can be provided as public information. PSCo is evaluating this request.

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PSCo

Colorado Energy Plan (CEP) — In 2016, PSCo filed its 2016 Electric Resource Plan (ERP) ~~— In May 2016, PSCo filed its 2016 ERP~~ which included ~~its~~the estimated need for additional generation resources ~~and its proposal to acquire those resources~~ through ~~a competitive Request for Proposal (RFP) process. The CPUC issued its decision on Phase I in late April~~spring of 2024. In 2017, ~~approving the Phase I modeling assumptions to be used in Phase II and directed~~ PSCo ~~to file~~filed an updated capacity need prior to issuing any RFPs. PSCo plans to update the range of resource need to be considered within the competitive RFP process and issue the RFP in August 2017. The CPUC is expected to rule on the RFP results in the second quarter of 2018.

~~Advanced Grid Intelligence and Security~~ ~~— In July 2017,~~with the CPUC ~~approved PSCo’s CPCN for implementation~~ of its advanced grid initiative. The project incorporates installing advanced meters, implementing hardware and software applications to allow the distribution system to operate at a lower voltage (integrated volt-var optimization) and installing communications infrastructure. These major projects are expected to improve customer experience, enhance grid reliability and enable the implementation of new and innovative programs and rate structures.450 MW in 2023.

In ~~June~~ 2017, PSCo and various other stakeholders filed a stipulation agreement (Stipulation) proposing the ~~CPUC approved a settlement, which delayed~~CEP, an alternative plan that increases the ~~advanced meter deployment from 2017-2021~~amount of new renewable resources sought under the ERP. The CEP would increase PSCo’s potential capacity need up to ~~2019-2024.~~1,110 MW due to the proposed retirement of two coal units. The ~~total capital cost~~major components include:

Early retirement of 660 MWs of coal-fired generation at Comanche Units 1 (2022) and 2 (2025);

Accelerated depreciation for the early retirement of the ~~project is currently estimated~~two Comanche units and establishment of a regulatory asset to ~~be approximately $537 million~~collect the incremental depreciation expense and related costs;

A request for ~~2017-2024. As a result~~proposal (RFP) for up to 1,000 MW of wind, 700 MW of solar and 700 MW of natural gas and/or storage;

Utility ownership targets of 50 percent renewable generation resources and 75 percent of natural gas-fired, storage, or renewable with storage generation resources; and

Reduction of the ~~settlement, approximately $120 million of capital investment was deferred~~renewable energy standard adjustment rider (RESA), from two percent to ~~2022-2024.~~

~~Decoupling Filing~~ — In July 2016, PSCo filed a request with the CPUC to approve a partial decoupling mechanism, which would adjust annual revenues based on changes in weather normalized average use per customer for the residential and small commercial classes. one percent effective beginning 2021 or 2022.

In ~~July 2017,~~March 2018, the CPUC ~~issued~~required additional portfolio requirements beyond the terms of the Stipulation. The CPUC requested PSCo to present 750 MW and 1,100 MW portfolios, and to include a ~~decision which approved the following key decisions regarding decoupling:~~

~~Effective Jan. 1, 2018 through December 2023 (subject to establishing new rates~~least-cost portfolio in ~~the next electric rate case);~~

~~Applicable~~addition to the ~~residential class~~recommended portfolio. They also requested a scenario without the RESA reduction offsetting the cost of accelerated depreciation. The order did not explicitly approve the Stipulation and ~~small commercial class;~~

~~Based~~deferred action on ~~total class revenues (subject to establishing~~issues such as the ~~base period~~treatment of accelerated depreciation which is being addressed in ~~the next electric rate case);~~

~~Based on actual sales; and~~

~~Subject to~~ a ~~soft cap of 3 percent on any annual adjustment.~~separate proceeding.

PSCo ~~plans to seek reconsideration of the order.~~

~~Boulder, Colo. Municipalization~~ ~~— In 2011, Boulder voters passed~~is currently evaluating bids from a ballot measure authorizing the formation of a municipal utility. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility as premature because costsRFP and system separation plans were not final. The Boulder District Court dismissed the case for lack of subject matter jurisdiction. PSCo appealed this decision. In September 2016, the Colorado Court of Appeals vacated the District Court’s decision, and ultimately preserved PSCo’s ability to challenge the utility formation. Boulder subsequently filed a Petition for Writ of Certiorari with the Colorado Supreme Court. The Supreme Court has not yet ruled whether it will exerciseanticipates filing its ~~discretion and review the petition.~~

~~In January 2015, the Boulder District Court affirmed a prior~~recommended portfolios in May 2018. A CPUC decision ~~that Boulder cannot serve customers outside its city limits. The District Court also ruled~~on the ~~CPUC has jurisdiction over~~recommended portfolio is anticipated in the ~~transfer~~summer of any facilities to Boulder and how the systems are separated to preserve reliability, safety and effectiveness. In February 2015, the Boulder District Court also dismissed the condemnation action Boulder had filed. The CPUC must approve the separation plan before Boulder files its condemnation proceeding.

In July 2015, Boulder filed an application with the CPUC requesting approval of its proposed separation plan. PSCo filed a motion to dismiss Boulder’s application. The CPUC dismissed a portion of Boulder’s application, but allowed Boulder to supplement its application. Boulder filed its second supplemental application in September 2016. In March 2017, PSCo and other parties filed their testimony outlining their concerns about the Boulder separation plan and raised legal concerns about aspects of the plan. In April 2017, despite extensive negotiations between PSCo and Boulder, the Boulder City Council voted to continue litigation for municipalization. Also, the CPUC ordered Boulder to file a third supplemental separation plan clearly laying out Boulder’s proposal. Boulder proposed a plan that would cost approximately $75 million. Boulder proposed sharing of certain distribution and substation facilities and requested that PSCo be required to construct Boulder’s new facilities and finance the construction. In June 2017, PSCo and other intervenors filed alternatives to Boulder’s separation plan and opposed the sharing; contracting and financing aspects of the plan. Evidentiary hearings began July 26, 2017.

~~Table of Contents~~

2018.

Mountain West Transmission Group (MWTG) — PSCo, ~~initiated discussions~~along with ~~six~~nine other ~~transmission owners~~electric service providers from the Rocky Mountain region, ~~to evaluate the merits of~~had considered creating and operating ~~pursuant to~~ a joint transmission tariff ~~that may~~to increase wholesale market efficiency and improve regional transmission planning. ~~In 2016, the~~The MWTG ~~established a non-binding memorandum of understanding~~sought opportunities to ~~guide their process~~reduce customer costs, and ~~issued a request for information to four established RTOs. In January 2017, the MWTG initiated preliminary discussions~~maximize resource and electric grid utilization. Negotiations with the SPP commenced in 2017 in order to ~~begin evaluation of the costs and benefits of MWTG~~develop potential terms for participation in the Regional Transmission Organization. As these negotiations developed, PSCo determined that the likely level of benefits was not sufficient to support continued engagement. On April 20, 2018, PSCo notified SPP, ~~RTO.~~regulators and the other MWTG utility members that it was ending its participation in the regional effort.

Public Utility Regulatory Policies Act (PURPA) Enforcement Complaint against CPUC — Sustainable Power Group, LLC (sPower) has proposed to construct 800 MW of solar generation and 700 MW of wind generation in Colorado and is seeking to require PSCo to contract for these resources under PURPA. In 2017, sPower filed a complaint for declaratory and injunctive relief in the United States District Court for the District of Colorado (District Court) requesting that the court find a December 2016 CPUC ruling that a qualifying facility must be a successful bidder in a PSCo resource acquisition bidding process violated PURPA and FERC rules. PSCo intervened in that proceeding and the CPUC filed a motion to dismiss. In June 2017, the United States Magistrate Judge issued a recommendation to the District Court that sPower’s complaint be dismissed because sPower failed to establish that it faced a substantial risk of harm. In October 2017, the District Court denied the CPUC’s motion to dismiss and instead allowed sPower to file an amended complaint. The case effectively started over, and PSCo intervened. The CPUC ~~has held informational meetings on certain issues including financial implications and reliability. If PSCo were~~filed a motion to ~~move forward with RTO participation,~~dismiss the amended complaint which is currently pending before the District Court. In February 2018, the Magistrate Judge recommended the CPUC motion to dismiss be denied. The CPUC and PSCo filed objections in March 2018. The timing of a resolution in this case is unclear.

OATT Reform — In late March 2018, PSCo filed for changes to its OATT with the FERC. The tariff change would allow large generating interconnection agreements to be suspended only due to a force majeure event and would apply only to new contracts on a prospective basis. In April 2018, certain parties filed comments opposing the PSCo tariff change. FERC ~~approval would be required. If approved, operations within the RTO would not be expected~~action is pending. PSCo has also initiated a larger stakeholder process to ~~begin until 2019, at the earliest. PSCo will evaluate its options~~achieve broader queue reform and anticipates filing additional tariff changes later in ~~2017 and beyond.~~2018. On April 19, 2018, FERC issued a final rule requiring queue reforms in addition (but generally complimentary) to reforms PSCo already contemplated; compliance tariff filings will be due in third quarter 2018. PSCo currently has more than 22,000 MW of new generator projects in its interconnection queue.

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SPS

~~TUCO Substation to Yoakum County Substation to Hobbs Plant Substation 345 KV Transmission Line~~— ~~In March 2016, the PUCT approved SPS’ Certificate of Convenience and Necessity (CCN)~~Lubbock Power & Light’s (LP&L’s) Request for the 33-mile Yoakum County to Texas/New Mexico State line portion of this 345 KV line project. A CCN for the 111-mile TUCO to Yoakum County substation segment was filed in June 2016. Assuming approval of this CCN, this segment is scheduled to be in service in 2020. A 36-mile CCN for the Texas/New Mexico state line to Hobbs Plant segment was filed in June 2017. The estimated project cost for all three segments is approximately $242 million.

~~Wholesale Customer~~ Participation in Electric Reliability Council of Texas (ERCOT) — In ~~March 2016,~~September 2017, LP&L filed its application with the PUCT ~~Staff requested comments on Lubbock Power & Light’s (LP&L’s) proposal~~and proposed to transition a portion of its load ~~(approximately 430 MW on~~to ERCOT no later than June 2021. As a ~~peak basis) to the ERCOT in June 2019.~~result of LP&L’s proposal, ~~would result in an approximate seven percent reduction of load in SPS, or a loss of~~ approximately $18 million in wholesale transmission ~~revenue. The~~revenue would be reallocated to remaining ~~portion~~SPS transmission customers at the time of the load transition. In November 2017, SPS and various other parties, including the PUCT Staff, filed direct testimony in response to LP&L’s application. SPS proposed an Interconnection Switching Fee to be determined by the PUCT.

In February 2018, SPS, LP&L, the PUCT Staff and various other parties filed a stipulation that provides SPS’ customers with an Interconnection Switching Fee of approximately $24 million to compensate them for the transfer of LP&L’s load ~~(approximately 170 MW)~~from SPP to ERCOT. Under the settlement, SPS would ~~continue~~allocate the Interconnection Switching Fee to ~~be served by SPS. Should LP&L join ERCOT, costs to SPS’ remaining~~its Texas and New Mexico retail and wholesale transmission customers ~~would increase as SPS’ transmission costs would be spread across~~through a ~~smaller base of customers.~~

~~The PUCT has indicated there will be a two-step process regarding~~bill credit following LP&L’s ~~possible transfer~~load transition to ERCOT. The ~~first step will be~~PUCT approved the stipulation in March 2018. LP&L has announced its intention to transfer to ERCOT effective June 1, 2021.

Texas State Right of First Refusal (ROFR) Request for Declaratory Order — In February 2017, SPS and SPP filed a proceeding to determine whether the proposed transfer is in the public interest and to consider certain protections for non-LP&L customers who would be affected by LP&L’s transfer. If the PUCT determines the transfer is in the public interest, the second step will be for LP&L to file a CCN application for transmission facilities to connect with ERCOT. The PUCT asked SPP and ERCOT to perform reliability and economic studies to better understand the implications of LP&L’s proposal. SPP and ERCOT filed the studies on June 30, 2017. LP&L is expected to file an applicationjoint petition with the PUCT for a ~~public interest determination~~declaratory order regarding SPS’ ROFR. SPS contended that Texas law grants an incumbent electric utility, operating in ~~August 2017. SPS intends~~areas outside of ERCOT, the ROFR to ~~participate~~construct new transmission facilities located in the utility’s service area. SPP stated that Texas law does not provide a clear statement regarding the ROFR for incumbent utilities and therefore SPP was abiding by the portion of its OATT, which requires competitive solicitation to construct and operate new transmission facilities within areas of Texas’ SPP footprint.

In October 2017, the PUCT issued an order finding that SPS does not possess an exclusive right to construct and operate transmission facilities within its service area. In January 2018, SPS and two other parties filed appeals of the PUCT’s ~~processes to protect its customers’ interests.~~order in the Texas State District Court. The appeals have been consolidated and the case is being briefed.

~~No final decision regarding LP&L’s departure or its potential timing is expected until completion~~Wind Proposals — In 2017, SPS filed proposals with the NMPRC and the PUCT to build, own and operate 1,000 MW of new wind generation through two wind farms (the Hale wind project in Texas and the Sagamore wind project in New Mexico) for a cost of approximately $1.6 billion. In addition, the proposal includes a purchased power agreement for 230 MW of wind.

In March 2018, the NMPRC approved SPS’ request consistent with the terms of SPS’ and the parties’ modified unanimous settlement. The key terms of the ~~PUCT proceedings.~~settlement are:

An investment cap of $1,675 per kilowatt, which is equal to 102.5 percent of the estimated construction costs;

SPS customers would receive a credit to their bills if actual capacity factors fall below 48 percent;

SPS customers would receive 100 percent of the federal PTC; and

SPS will sell the output from the two wind farms into the market and keep the revenue and the grossed-up PTCs during the time the rate case is pending before the wind projects go into base rates. If the market revenue and grossed up PTC value exceeds the estimated revenue requirement, SPS will refund the excess amount to customers as an additional customer protection during the interim period.

In February 2018, SPS and the parties filed an unopposed settlement with the PUCT. The key terms of the settlement are similar to the terms approved by the NMPRC above except that the ratemaking treatment of the market revenues and grossed-up PTCs will be treated in a traditional ratemaking manner and the effective date of the rates in the rate cases placing the wind farms in rates will be 35 days after SPS files the rate cases.

In April 2018, the PUCT requested additional information regarding the settlement. SPS filed a response and the PUCT is scheduled to consider the settlement April 27, 2018.

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Summary of Recent Federal Regulatory Developments

FERC

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of Xcel Energy Inc.’s utility subsidiaries and transmission-only subsidiaries, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of Xcel Energy Inc.’s utility subsidiaries’ activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2016 and Quarterly Report on Form 10-Q for the quarterly period ended March 31,~~ 2017. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

~~Status of FERC Commissioners~~ — The FERC is normally comprised of five commissioners appointed by the President and confirmed by the Senate. There is currently only one sitting commissioner. Without three commissioners, the FERC does not have a quorum to act on contested matters. The lack of a quorum could affect the timing of FERC decisions on proposed rules or pending, newly submitted and future filings involving, among other things, contested electric rate matters and CPCNs for construction of interstate natural gas pipeline facilities to serve the utility subsidiaries. Xcel Energy ~~does not expect any disruption in operations or material delay in decisions~~attempts to mitigate the risk of regulatory penalties through formal training on ~~contested matters pending before~~prohibited practices and a compliance function that reviews interaction with the ~~FERC. President Trump has submitted nominations~~markets under FERC and Commodity Futures Trading Commission jurisdictions. Public campaigns are conducted to ~~fill three~~raise awareness of the ~~vacant seats and has indicated his intent~~public safety issues of interacting with our electric systems. While programs to ~~submit one additional nomination. The three submitted nominations~~comply with regulatory requirements are ~~pending confirmation by~~in place, there is no guarantee the ~~full Senate.~~

~~Table of Contents~~

compliance programs or other measures will be sufficient to ensure against violations.

FERC Order, ROE Policy — In June 2014, the FERC adopted a two-step ROE methodology for electric utilities in an order (Opinion 531) issued in a complaint proceeding involving New England Transmission Owners (NETOs). The issue of how to apply the FERC ROE methodology has been contested in various complaint proceedings, including two ROE complaints involving the MISO TOs, which ~~includes~~include NSP-Minnesota and NSP-Wisconsin. In April 2017, the D.C. Circuit vacated and remanded the June 2014 ROE order. The D.C. Circuit found that the FERC had not properly determined that the ROE authorized for the NETOs prior to June 2014 was unjust and unreasonable. The D.C. Circuit also found that the FERC failed to justify the new ROE methodology. The FERC has yet to act on the D.C. Circuit’s ~~decision and cannot act without a quorum.~~decision. See Note 5 to the consolidated financial statements for discussion of the D.C. Circuit’s decision and the impact on the MISO ROE Complaints.

~~Public Utility Regulatory Policies Act (PURPA) Enforcement Complaint against CPUC~~ —In December 2016, Sustainable Power Group, LLC (sPower) petitioned the FERC to initiate an enforcement action in federal court against the CPUC under PURPA. The petition asserts that a December 2016 CPUC ruling, which indicated that a qualifying facility must be a successful bidder in a PSCo resource acquisition bidding process, violated PURPA and FERC rules. In January 2017, PSCo filed a motion to intervene and protest, arguing that the FERC should decline the petition. The CPUC filed a similar pleading. sPower has proposed to construct 800 MW of solar generation and 700 MW of wind generation in Colorado and seeks to require PSCo to contract for these resources under PURPA. If sPower were to prevail, PSCo’s ability to select generation resources through competitive bidding would be negatively affected. However, due to a lack of quorum at the FERC, the FERC did not act on that petition within the sixty days contemplated by PURPA. Subsequently sPower filed a complaint for declaratory and injunctive relief in the United States District Court for the District of Colorado (District Court) requesting that the court find the bidding requirement in the CPUC qualifying facility rules to be unlawful. PSCo has intervened in that proceeding and the CPUC has filed a motion to dismiss. In June 2017, the United States Magistrate Judge (Magistrate) issued a recommendation to the District Court that sPower’s complaint be dismissed because sPower failed to establish that it faced a substantial risk of harm. The Magistrate’s recommendation is pending before the District Court.

~~Solar Gardens Investment~~

In July 2017, a newly formed subsidiary of Xcel Energy signed an agreement with a solar developer to construct and operate approximately 19 MW of new community solar gardens in Minnesota serving existing NSP-Minnesota customers. The projects are expected to achieve commercial operations in 2017 and 2018.

Derivatives, Risk Management and Market Risk

Xcel Energy Inc. and its subsidiaries are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. See Note 8 to the consolidated financial statements for further discussion of market risks associated with derivatives.

Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, when necessary, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While Xcel Energy expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose Xcel Energy to some credit and non-performance risk.

Though no material non-performance risk currently exists with the counterparties to Xcel Energy’s commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties. Distress in the financial markets may also impact the fair value of the securities in the nuclear decommissioning fund and master pension trust, as well as Xcel Energy’s ability to earn a return on short-term investments of excess cash.

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

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At ~~June 30, 2017,~~March 31, 2018, the fair values by source for net commodity trading contract assets were as follows:

Futures / Forwards
(Thousands of Dollars) Source of Fair Value Maturity
Less Than 1 Year Maturity 1 to 3 Years Maturity 4 to 5 Years Maturity
Greater Than 5 Years Total Futures/
Forwards Fair Value
NSP-Minnesota 1
$ 1,928
$ 6,534
$ 1,550
$ —
$ 10,012
PSCo 1
396
(11 ) —
—
385
PSCo 2
1
—
—
—
1
$ 2,325
$ 6,523
$ 1,550
$ —
$ 10,398


	Options												Futures / Forwards
(Thousands of Dollars)	Source of Fair Value	Maturity Less Than 1 Year			Maturity 1 to 3 Years		Maturity 4 to 5 Years		Maturity Greater Than 5 Years		Total Futures/ Forwards Fair Value
(Millions of Dollars)													Source of Fair Value	Maturity Less Than 1 Year		Maturity 1 to 3 Years		Maturity 4 to 5 Years		Maturity Greater Than 5 Years		Total Futures/ Forwards Fair Value
NSP-Minnesota	2	$	(512	)	$	2,129	$	3,042	$	—	$	4,659	1	$	4	$	9	$	1	$	1	$	15
PSCo													1	1		—		—		—		1
														$	5	$	9	$	1	$	1	$	16

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

~~2 — Prices based on models and other valuation methods.~~

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


	Six Months Ended June 30						Three Months Ended March 31
(Thousands of Dollars)	2017			2016
(Millions of Dollars)							2018			2017
Fair value of commodity trading net contract assets outstanding at Jan. 1	$	9,771		$	11,040		$	16		$	9
Contracts realized or settled during the period	(5,998		)	(1,406		)	(2		)	—
Commodity trading contract additions and changes during the period	11,284			460			3			1
Fair value of commodity trading net contract assets outstanding at June 30	$	15,057		$	10,094
Fair value of commodity trading net contract assets outstanding at March 31							$	17		$	10

At ~~June 30,~~March 31, 2018, a 10 percent increase in market prices for commodity trading contracts would decrease pretax income from continuing operations by approximately $1 million, whereas a 10 percent decrease would increase pretax income from continuing operations by approximately $1 million. At March 31, 2017, a 10 percent increase in market prices for commodity trading contracts would ~~increase pretax income from continuing operations by approximately $0.3 million, whereas a 10 percent decrease would~~ decrease pretax income from continuing operations by approximately ~~$0.8 million. At June 30, 2016,~~$1 million, whereas a 10 percent ~~increase in market prices for commodity trading contracts~~decrease would increase pretax income from continuing operations by approximately ~~$0.1 million, whereas a 10 percent decrease would decrease pretax income from continuing operations by approximately $0.1~~$1 million.

Xcel Energy Inc.’s utility subsidiaries’ wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value at Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions.

The VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis using a Monte Carlo simulation with a 95 percent confidence level and a one-day holding period, were as follows:

(Millions of Dollars) Three Months Ended June 30 VaR Limit Average High Low
2017 $ 0.26
$ 3.00
$ 0.38
$ 0.66
$ 0.04
2016 0.22
3.00
0.22
0.38
0.06

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(Millions of Dollars)	Three Months Ended March 31		VaR Limit		Average		High		Low
2018	$	0.32	$	3.00	$	0.22	$	0.57	$	0.10
2017	0.42		3.00		0.16		0.62		0.04

Nuclear Fuel Supply — NSP-Minnesota is scheduled to take delivery of approximately 1358 percent of its ~~2017~~2018 and approximately 5424 percent of its ~~2018~~2019 enriched nuclear material requirements from sources that could be impacted by current political/world events, ~~in Ukraine and sanctions against~~ including those related to Ukraine/Russia. Alternate potential sources are expected to provide the flexibility to manage NSP-Minnesota’s nuclear fuel supply to ensure that plant availability and reliability will not be negatively impacted in the near-term. Long-term, through 2024, NSP-Minnesota is scheduled to take delivery of approximately 3135 percent of its average enriched nuclear material requirements from ~~sources that could be impacted by events in Ukraine and extended sanctions against Russia.~~these sources. NSP-Minnesota is closely following the progression of these events and will periodically assess if further actions are required to assure a secure supply of enriched nuclear material.

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Separately, NSP-Minnesota has enriched nuclear fuel materials in process with Westinghouse Electric Corporation (Westinghouse). Westinghouse filed for Chapter 11 bankruptcy protection in March 2017. NSP-Minnesota owns materials in Westinghouse’s inventory and has contracts in place under which Westinghouse will provide certain services during an upcoming outage at PI. Westinghouse will provide nuclear fuel assemblies for the upcoming PI outage under the current nuclear fuel fabrication contract. Westinghouse has indicated its intention to continue to perform under the arrangements. Based on Westinghouse’s stated intent and the interim financing secured to fund its on-going operations, NSP-Minnesota does not expect the bankruptcy to materially impact NSP-Minnesota’s operational or financial performance. Westinghouse announced on Jan. 4, 2018 it has agreed to be acquired by Brookfield Business Partners LP and other institutional partners. Brookfield’s acquisition of Westinghouse is expected to close in the third quarter of 2018, subject to bankruptcy court and regulatory approvals. NSP-Minnesota will continue to monitor the Westinghouse acquisition process.

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

At ~~June 30,~~March 31, 2018 and 2017, ~~and 2016,~~ a 100-basis-point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately ~~$9.4~~$11 million and ~~$5.9~~$6 million, respectively. See Note 8 to the consolidated financial statements for a discussion of Xcel Energy Inc. and its subsidiaries’ interest rate derivatives.

NSP-Minnesota also maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. At ~~June 30, 2017,~~March 31, 2018, the fund was invested in a diversified portfolio of cash equivalents, debt securities, equity securities, and other investments. These investments may be used only for activities related to nuclear decommissioning. 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. Since the accounting for nuclear decommissioning recognizes that costs are recovered through rates, fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings.

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

At ~~June 30, 2017,~~March 31, 2018, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of ~~$18.1~~$22 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of ~~$2.1~~$11 million. At ~~June 30, 2016,~~March 31, 2017, a 10 percent increase in commodity prices would have resulted in ~~a decrease~~an increase in credit exposure of ~~$9.2~~$11 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of ~~$16.4~~$2 million.

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

Fair Value Measurements

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

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Commodity Derivatives — Xcel Energy continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at ~~June 30, 2017.~~March 31, 2018. Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are deferred as other comprehensive income (OCI) or regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at ~~June 30, 2017.~~March 31, 2018.

Commodity derivative assets and liabilities assigned to Level 3 typically consist of FTRs, as well as forwards and options that are long-term in nature. Level 3 commodity derivative assets and liabilities represent ~~3.5~~0.9 percent and ~~9.8~~3.7 percent of total assets and liabilities, respectively, measured at fair value at ~~June 30, 2017.~~March 31, 2018.

Determining the fair value of FTRs requires numerous management forecasts that vary in observability, including various forward commodity prices, retail and wholesale demand, generation and resulting transmission system congestion. Given the limited ~~observability of management’s forecasts~~transparency in the auction process, fair value measurements for ~~several of these inputs, these instruments~~FTRs have been assigned a Level 3. Level 3 commodity derivatives assets and liabilities included ~~$68.1~~$13 million and ~~$4.0~~$1 million of estimated fair values, respectively, for FTRs held at ~~June 30, 2017.~~March 31, 2018.

Determining the fair value of certain commodity forwards and options can require management to make use of subjective price and volatility forecasts which extend to periods beyond those readily observable on active exchanges or quoted by brokers. When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3. There were ~~$5.2~~$6 million in Level 3 commodity derivative assets and no liabilities for options held at ~~June 30, 2017.~~March 31, 2018. There were ~~immaterial~~$2 million of Level 3 derivative assets held as forwards ~~held~~ at ~~June 30, 2017.~~March 31, 2018.

Liquidity and Capital Resources

Cash Flows


	Six Months Ended June 30				Three Months Ended March 31
(Millions of Dollars)	2017		2016		2018		2017
Cash provided by operating activities	$	1,292	$	1,425	$	887	$	718

Net cash provided by operating activities ~~decreased $133~~increased $169 million for the ~~six~~three months ended ~~June 30, 2017~~March 31, 2018 compared with the ~~six~~three months ended ~~June 30, 2016.~~March 31, 2017. The ~~decrease~~increase was primarily due to ~~lower tax refunds received and~~ the timing of ~~vendor payments, customer receipts, refunds, and~~ recovery of certain electric and natural gas riders and incentive programs, partially offset by ~~higher~~lower net income, excluding amounts related to non-cash operating activities (e.g., depreciation and deferred tax ~~expenses)~~expense).


	Six Months Ended June 30						Three Months Ended March 31
(Millions of Dollars)	2017			2016			2018			2017
Cash used in investing activities	$	(1,474	)	$	(1,443	)	$	(872	)	$	(748	)

Net cash used in investing activities increased ~~$31~~$124 million for the ~~six~~three months ended ~~June 30, 2017~~March 31, 2018 compared with the ~~six~~three months ended ~~June 30, 2016.~~March 31, 2017. The increase was primarily attributable to higher capital expenditures related to the Rush Creek wind generation ~~facility, partially offset by lower rabbi trust investments in 2017.~~facility.


	Six Months Ended June 30				Three Months Ended March 31
(Millions of Dollars)	2017		2016		2018		2017
Cash provided by financing activities	$	159	$	10	$	18	$	19

Net cash provided by financing activities ~~increased $149~~was $18 million for the ~~six~~three months ended ~~June 30, 2017~~March 31, 2018 compared with net cash provided by financing activities of $19 million for the ~~six~~three months ended ~~June 30,~~March 31, 2017. The ~~increase~~change was primarily attributable to ~~lower repayments of long-term debt, partially offset by lower debt proceeds (net) year over year and higher~~increased 2018 dividend payments.

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Capital Requirements

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

Regulation of Derivatives — In ~~July~~ 2010, financial reform legislation was passed that provides for the regulation of derivative transactions amongst other provisions. ~~Provisions within the bill provide the~~The Commodity Futures Trading Commission ~~(CFTC) and the SEC with expanded regulatory authority over derivative and swap transactions. The CFTC~~ ruled that swap dealing activity conducted by entities for the preceding 12 months under a notional limit, initially set at $8 billion, will fall under the general de minimis threshold and will not subject an entity to registering as a swap dealer. The de minimis threshold is scheduled to be reduced to $3 billion ~~in 2018.~~at the end of 2019. Xcel Energy’s current and projected swap activity is well below these de minimis thresholds. The bill also contains provisions that exempt certain derivatives end users from much of the clearing and margin requirements and Xcel Energy’s Board of Directors has renewed the end-user exemption on an annual basis. Xcel Energy is currently meeting all reporting requirements and transaction restrictions.

~~Southwest Power Pool Inc. (SPP) FTR Margining Requirements~~ — In SPP, the process for TOs involves the receipt of Auction Revenue Rights (ARRs) and, if elected by the TO, conversion of those ARRs to firm FTRs. SPP requires that the TO post collateral for the conversion of ARRs to FTRs. At June 30, 2017, SPS had a $2.5 million letter of credit posted with SPP for the annual FTR auction, which was a reduction from the initial requirement of $15 million.

Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities, and alternative investments, including private equity, real estate and hedge ~~fund of funds and commodity investments.~~funds.

In January ~~2017,~~2018, contributions of ~~$150.0~~$150 million were made across four of Xcel Energy’s pension plans;

In ~~2016,~~2017, contributions of ~~$125.2~~$162 million were made across four of Xcel Energy’s pension plans; and

For future years, contributions will be made as deemed appropriate based on evaluation of various factors including the funded status of the plans, minimum funding requirements, interest rates and expected investment returns.

Capital Sources

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

Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts. At ~~June 30, 2017,~~March 31, 2018, approximately ~~$1.8~~$38 million of cash was held in these accounts.

Credit Facilities — NSP-Minnesota, NSP-Wisconsin, PSCo, SPS and Xcel Energy Inc. each have five-year credit agreements with a syndicate of banks. The total size of the five-year credit facilities is $2.75 billion, and each credit facility terminates in June 2021.

NSP-Minnesota, PSCo, SPS and Xcel Energy Inc. each have the right to request an extension of the revolving credit facility termination date for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.

Xcel Energy Inc. entered into a 364-Day Term Loan Agreement on Dec. 5, 2017 to borrow up to $500 million. As of March 31, 2018, Xcel Energy Inc. had drawn $500 million on the term loan. Xcel Energy Inc. may recommit for one additional 364-day period from the December 2018 maturity date, subject to majority consent from lenders.

As of ~~July 24, 2017,~~April 23, 2018, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:


(Millions of Dollars)	Credit Facility ^(a)		Drawn ^(b)		Available		Cash		Liquidity		Credit Facility ^(a)		Drawn ^(b)		Available		Cash		Liquidity
Xcel Energy Inc.	$	1,000	$	483	$	517	$	5	$	522	$	1,500	$	775	$	725	$	1	$	726
PSCo	700		3		697		1		698		700		54		646		1		647
NSP-Minnesota	500		145		355		1		356		500		36		464		1		465
SPS	400		101		299		—		299		400		19		381		1		382
NSP-Wisconsin	150		70		80		—		80		150		36		114		—		114
Total	$	2,750	$	802	$	1,948	$	7	$	1,955	$	3,250	$	920	$	2,330	$	4	$	2,334


^(a)	These credit facilities expire in June ~~2021.~~2021, with the exception of Xcel Energy Inc.’s $500 million 364-day term loan agreement entered into in December 2017.


^(b)	Includes outstanding commercial paper, term loan borrowings and letters of credit.

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~~Commercial Paper~~Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. The authorized levels for these commercial paper programs are:

$1 billion for Xcel Energy Inc.;

$700 million for PSCo;

$500 million for NSP-Minnesota;

$400 million for SPS; and

$150 million for NSP-Wisconsin.

~~Commercial paper~~In addition, Xcel Energy Inc. has a 364-day term loan agreement to borrow up to $500 million. At March 31, 2018, Xcel Energy Inc. had drawn $500 million on the term loan.

Short-term debt outstanding for Xcel Energy was as follows:


(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2017			Year Ended Dec. 31, 2016			Three Months Ended March 31, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	2,750		$	2,750		$	3,250		$	3,250
Amount outstanding at period end	784			392			1,025			814
Average amount outstanding	778			485			1,000			644
Maximum amount outstanding	1,247			1,183			1,197			1,247
Weighted average interest rate, computed on a daily basis	1.28		%	0.74		%	1.93		%	1.35		%
Weighted average interest rate at period end	1.49			0.95			2.34			1.90

Money Pool — Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings between the utility subsidiaries. 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.

NSP-Minnesota, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions. NSP-Wisconsin does not participate in the money pool.

Financing — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes.

~~During 2017,~~ Xcel Energy Inc. and its utility ~~subsidiaries issued and anticipate issuing~~subsidiaries’ 2018 financing plans reflect the following:

~~PSCo issued $400 million of 3.80 percent first mortgage bonds due June 15, 2047;~~

Xcel Energy Inc. plans to issue approximately ~~$300~~$750 million of senior unsecured ~~bonds in the fourth quarter;~~bonds;

NSP-Minnesota plans to issue approximately ~~$600~~$300 million of first mortgage ~~bonds in the third quarter;~~bonds;

NSP-Wisconsin plans to issue approximately ~~$100~~$200 million of first mortgage ~~bonds in the fourth quarter;~~bonds;

PSCo plans to issue approximately $750 million of first mortgage bonds; and

SPS plans to issue approximately ~~$450~~$350 million of first mortgage ~~bonds~~bonds.

Xcel Energy also plans to issue approximately $300 million of incremental equity in 2018 in addition to $75 million of equity to be issued through the ~~third quarter.~~dividend reinvestment program and benefit programs.

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

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Off-Balance-Sheet Arrangements

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

Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives

Xcel Energy 2018 Earnings Guidance — Xcel Energy’s ~~2017~~2018 GAAP and ongoing earnings guidance is ~~$2.25~~$2.37 to ~~$2.35~~$2.47 per share.^(a)Key ~~assumptions related to 2017 earnings are detailed below:~~assumptions:

Constructive outcomes in all rate case and regulatory proceedings.

Normal weather ~~patterns are experienced for the remainder of the year.~~patterns.

Weather-normalized retail electric ~~utility~~ sales are projected to ~~increase~~be within a range of 0 percent to 0.5 ~~percent.~~percent over 2017 levels.

Weather-normalized retail firm natural gas sales are projected to ~~increase~~be within a range of 0 percent to 0.5 ~~percent.~~

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percent over 2017 levels.

Capital rider revenue is projected to increase by ~~$50~~$30 million to ~~$60~~$40 million over ~~2016~~2017 levels. ~~The change is largely due to the level of PTC, which flows~~PTCs are flowed back to ~~customers.~~customers, primarily through capital riders and reductions to electric margin.

O&M expenses are projected to be ~~flat.~~flat to 2017 levels.

Depreciation expense is projected to increase approximately ~~$180~~$120 million to ~~$190~~$130 million over ~~2016~~2017 levels. The change inis depreciation expense is largely due to ~~changes in~~ the ~~amortization~~dismissal of the ~~renewable development fund,~~PSCo electric rate case, which ~~is offset in revenue and will not have an~~delays the impact ~~on earnings.~~of higher depreciation rates.

Property taxes are projected to increase approximately $0$30 million to ~~$10~~$40 million over ~~2016~~2017 levels.

Interest expense (net of AFUDC —- debt) is projected to increase ~~$15~~$30 million to ~~$25~~$40 million over ~~2016~~2017 levels.

AFUDC —- equity is projected to increase approximately $5$20 million to ~~$15~~$30 million from ~~2016~~2017 levels.

The ETR is projected to be approximately 3115 percent to 3317 percent. ~~The change is largely due~~This range may decrease to 8 percent to 10 percent as we receive clarity and direction from our commissions as to the ~~level~~treatment of ~~PTC,~~excess deferred taxes that resulted from the TCJA. A reduction to the ETR resulting from the flowback of excess deferred taxes would be offset by a correlated reduction to revenue. Additionally, the lower ETR for 2018 compared to 2017 reflects additional PTCs which ~~flows~~are flowed back to ~~customers.~~

~~Average common stock and equivalents are projected to be approximately 509 million shares.~~customers through margin.

^(a)

Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. Xcel Energy is unable to forecast if any of these items will occur or provide a quantitative reconciliation of the guidance for ongoing diluted EPS to corresponding GAAP diluted EPS.

Long-Term EPS and Dividend Growth Rate Objectives

Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:

Deliver long-term annual EPS growth of 45 percent to 6 ~~percent;~~percent off of a 2017 base of $2.30 per share;

Deliver annual dividend increases of 5 percent to 7 percent;

Target a dividend payout ratio of 60 percent to 70 percent; and

Maintain senior unsecured debt credit ratings in the BBB+ to A range.

~~Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective~~

Table of ~~ongoing operations.~~Contents

Item 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Management’s Discussion and Analysis — Derivatives, Risk Management and Market Risk under Item 2.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of ~~June 30, 2017,~~March 31, 2018, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

In 2016, Xcel Energy implemented the general ledger modules, as well as initiated deployment of work management systems modules, of a new enterprise resource planning system to improve certain financial and related transaction processes. Xcel Energy is continuing to implement additional modules including the conversion of existing work management systems to this same system during 2017. In connection with this ongoing implementation, Xcel Energy is updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting systems. Xcel Energy does not believe that this implementation will have an adverse effect on its internal control over financial reporting.

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

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Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

Additional Information

See Note 6 to the consolidated financial statements for further discussion of legal claims and environmental proceedings. See Part I Item 2 and Note 5 to the consolidated financial statements for a discussion of proceedings involving utility rates and other regulatory matters.

Item 1A — RISK FACTORS

Xcel Energy Inc.’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, ~~2016,~~2017, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table provides information about our purchases of equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Exchange Act for the quarter ended ~~June 30, 2017:~~March 31, 2018:



	Issuer Purchases of Equity Securities
Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
Jan. 1, 2018 — Jan. 31, 2018	—	$	—	—	—
Feb. 1, 2018 — Feb. 28, 2018 ^(a)	22,039	42.97		—	—
March 1, 2018 — March 31, 2018 ^(b)	12,028	43.28		—	—
Total	34,067			—	—

^(a)

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

~~Issuer Purchases of Equity Securities~~

~~Period~~

^(b)

~~Total Number~~Xcel Energy Inc. withholds stock to satisfy tax withholding obligations on vesting of
~~Shares Purchased~~

~~Average Price~~
~~Paid per Share~~

~~Total Number~~ awards of ~~Shares Purchased as Part of Publicly Announced Plans or Programs~~

~~Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under~~restricted stock under the ~~Plans or Programs~~

~~April 1, 2017 — April 30, 2017~~

—

~~May 1, 2017 — May 31, 2017~~

—

~~June 1, 2017 — June 30, 2017~~

—

~~Total~~

—

Xcel Energy Executive Annual Incentive Award Plan.

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Item 6 — EXHIBITS

* Indicates incorporation by reference

~~+ Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors~~



3.01* 3.01*	Amended and Restated Articles of Incorporation of Xcel Energy Inc., as filed on May 18, 2012 (Exhibit 3.01 to Form 8-K dated May 16, 2012 (file no. 001-03034)).
3.02* 3.02*	Bylaws of Xcel Energy Inc., as amended on Feb. 17, 2016 (Exhibit 3.01 to Form 8-K dated Feb. 18, 2016 (file no. 001-03034)).
4.01* 4.01*	Supplemental and Restated Trust Indenture, ~~No. 27~~ dated May 1, 1988, from Northern States Power Company to Harris Trust and Savings Bank, as Trustee, providing for the issuance of ~~June~~First Mortgage Bonds (Exhibit 4(b)(3) to Form S-3 of Xcel Energy, filed April 18, 2018 (file no. 333-224333)).
4.02*	Indenture, dated July 1, ~~2017~~1999, between ~~PSCo~~Northern States Power Company and ~~U.S.~~Norwest Bank Minnesota, National Association, as Trustee, ~~creating $400 million principal amount~~providing for the issuance of ~~3.80 percent~~Sr. Debt Securities (Exhibit 4(b)(7) to Form S-3 of Xcel Energy, filed April 18, 2018 (file no. 333-224333)).
4.03*	Indenture, dated as of Oct. 1, 1993, between PSCo and Morgan Guaranty Trust Company of New York, as trustee, providing for the issuance of first mortgage bonds (Exhibit 4(d)(3) to Form S-3 of Xcel Energy filed April 18, 2018 (file no. 333-224333)).
4.04*	Supplemental and Restated Indenture, dated March 1, 1991, between Northern States Power Company and First Wisconsin Trust Company, providing for the issuance of First Mortgage Bonds ~~Series No. 30 due 2047.~~ (Exhibit ~~4.01~~4(c)(3) to Form ~~8-K~~S-3 of ~~PSCo dated June 19, 2017~~Xcel Energy filed April 18, 2018 (file no. ~~001-03280)~~333-224333)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarter ended ~~June 30, 2017~~March 31, 2018 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) the Consolidated Statements of Common Stockholders’ Equity, (vi) Notes to Consolidated Financial Statements, and (vii) document and entity information.

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Table of Contents

SIGNATURES

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



		XCEL ENERGY INC.

~~July 28, 2017~~April 27, 2018	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)

		/s/ ROBERT C. FRENZEL
		Robert C. Frenzel
		Executive Vice President, Chief Financial Officer
		(Principal Financial Officer)

5552



(Millions of Dollars, incremental)	2016		2017		2018		2019			Total
Revenues	$	74.99	$	59.86	$	—	$	50.12		$	184.97
NSP-Minnesota’s sales true-up	59.95		—		—		(0.20		)	59.75
Total rate impact	$	134.94	$	59.86	$	—	$	49.92		$	244.72




	Six Months Ended June 30, 2017
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) 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	$	—	$	—		$	2,678		^(a)	$	—			$	—
Vehicle fuel and other commodity	43		—			(5		)	^(b)	—				—
Total	$	43	$	—		$	2,673			$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—			$	6,786		^(c)
Electric commodity	—		(505		)	—				(6,313		)	^(d)	—
Natural gas commodity	—		(7,846		)	—				1,075			^(e)	(4,070		)	^(e)
Total	$	—	$	(8,351	)	$	—			$	(5,238	)		$	2,716



	Six Months Ended June 30, 2016
	Pre-Tax Fair Value Gains (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	$	—	$	—		$	2,968	^(a)	$	—		$	—
Vehicle fuel and other commodity	13		—			104		^(b)	—			—
Total	$	13	$	—		$	3,072		$	—		$	—
Other derivative instruments

Commodity trading	$	—	$	—		$	—		$	—		$	1,490		^(c)
Electric commodity	—		(970		)	—			27,533		^(d)	—
Natural gas commodity	—		3,361			—			11,666		^(e)	(4,999		)	^(e)
Total	$	—	$	2,391		$	—		$	39,199		$	(3,509	)



Project Name	Capacity (MW)	State	Estimated Year of Completion	Ownership/PPA	Regulatory Status
Rush Creek	600	CO	2018	PSCo	Approved by CPUC
Freeborn	200	MN/IA	2020	NSP-Minnesota	Approved by MPUC
Blazing Star 1	200	MN	2019	NSP-Minnesota	Approved by MPUC
Blazing Star 2	200	MN	2020	NSP-Minnesota	Approved by MPUC
Lake Benton	100	MN	2019	NSP-Minnesota	Approved by MPUC
Foxtail	150	ND	2019	NSP-Minnesota	Approved by MPUC
Crowned Ridge	300	SD	2019	NSP-Minnesota	Approved by MPUC
Hale	478	TX	2019	SPS	Pending PUCT & NMPRC Approval
Sagamore	522	NM	2020	SPS	Pending PUCT & NMPRC Approval
Total Ownership	2,750

Crowned Ridge	300	SD	2019	PPA	Approved by MPUC
Clean Energy 1	100	ND	2019	PPA	Approved by MPUC
Bonita	230	TX	2019	PPA	Pending PUCT & NMPRC Approval
Total PPA	630