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 ~~Sept.~~June 30, ~~2016~~2017



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

Commission File Number: 001-3034

Xcel Energy Inc.

(Exact name of registrant as specified in its charter)



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

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

(612) 330-5500

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, ~~or a~~ smaller reporting company or an emerging growth company. See the definitions of “large accelerated ~~filer”,~~filer,” “accelerated ~~filer”~~filer,” “smaller reporting company,” and ~~“smaller reporting~~“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 ~~October~~July 24, ~~2016~~2017
Common Stock, $2.50 par value		~~507,952,795~~507,762,881 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	9
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3634
Item 3 —	Quantitative and Qualitative Disclosures about Market Risk	5752
Item 4 —	Controls and Procedures	5752

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	5853
Item 1A —	Risk Factors	5853
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	58
~~Item 4 —~~	~~Mine Safety Disclosures~~	58
~~Item 5 —~~	~~Other Information~~	5853
Item 6 —	Exhibits	5954

SIGNATURES		6055

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

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended June 30						Six Months Ended June 30
	2016			2015			2016			2015			2017			2016			2017			2016
Operating revenues
Electric	$	2,799,964		$	2,667,480		$	7,209,225		$	7,105,803		$	2,338,017		$	2,224,142		$	4,637,077		$	4,409,261
Natural gas	221,956			216,019			1,046,544			1,216,146			289,839			258,899			915,542			824,588
Other	18,227			17,813			56,500			56,716			17,072			16,808			38,731			38,273
Total operating revenues	3,040,147			2,901,312			8,312,269			8,378,665			2,644,928			2,499,849			5,591,350			5,272,122

Operating expenses
Electric fuel and purchased power	1,037,263			1,014,726			2,755,083			2,869,563			919,099			855,968			1,844,320			1,717,820
Cost of natural gas sold and transported	67,566			66,071			469,754			665,109			114,320			90,071			479,454			402,188
Cost of sales — other	8,648			8,203			25,225			26,416			8,178			8,332			16,765			16,577
Operating and maintenance expenses	590,009			565,984			1,764,397			1,746,093			578,133			596,978			1,164,563			1,174,388
Conservation and demand side management program expenses	63,914			57,314			177,266			165,260
Conservation and demand side management expenses													64,860			55,916			132,393			113,352
Depreciation and amortization	328,503			280,121			971,057			827,821			365,720			322,534			730,924			642,554
Taxes (other than income taxes)	117,190			123,081			400,982			389,438			134,926			138,469			277,020			283,792
Loss on Monticello life cycle management/extended power uprate project	—			—			—			129,463
Total operating expenses	2,213,093			2,115,500			6,563,764			6,819,163			2,185,236			2,068,268			4,645,439			4,350,671

Operating income	827,054			785,812			1,748,505			1,559,502			459,692			431,581			945,911			921,451

Other income, net	578			1,626			6,388			5,748			2,608			1,560			9,054			5,810
Equity earnings of unconsolidated subsidiaries	9,701			8,162			32,500			24,360			7,541			9,617			15,416			22,799
Allowance for funds used during construction — equity	17,199			15,427			45,042			40,728			16,386			14,730			30,699			27,843

Interest charges and financing costs
Interest charges — includes other financing costs of $6,060 $6,260, $19,026 and $17,819, respectively	165,857			152,566			485,280			441,728
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
Allowance for funds used during construction — debt	(7,532		)	(7,031		)	(20,206		)	(19,340		)	(7,613		)	(6,684		)	(14,635		)	(12,674		)
Total interest charges and financing costs	158,325			145,535			465,074			422,388			156,582			156,296			315,494			306,749

Income before income taxes	696,207			665,492			1,367,361			1,207,950			329,645			301,192			685,586			671,154
Income taxes	238,412			239,029			471,459			432,490			102,389			104,397			219,053			233,047
Net income	$	457,795		$	426,463		$	895,902		$	775,460		$	227,256		$	196,795		$	466,533		$	438,107

Weighted average common shares outstanding:
Basic	508,941			508,031			508,840			507,585			508,542			508,930			508,411			508,789
Diluted	509,566			508,427			509,396			507,976			509,135			509,490			508,955			509,311

Earnings per average common share:
Basic	$	0.90		$	0.84		$	1.76		$	1.53		$	0.45		$	0.39		$	0.92		$	0.86
Diluted	0.90			0.84			1.76			1.53			0.45			0.39			0.92			0.86

Cash dividends declared per common share	$	0.34		$	0.32		$	1.02		$	0.96		$	0.36		$	0.34		$	0.72		$	0.68

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

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30					Three Months Ended June 30				Six Months Ended June 30
	2016			2015			2016		2015			2017		2016		2017		2016
Net income	$	457,795		$	426,463		$	895,902	$	775,460		$	227,256	$	196,795	$	466,533	$	438,107

Other comprehensive income

Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $536, $559, $1,635 and $1,689, respectively	878			884			1,954		2,643
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

Derivative instruments:
Net fair value (decrease) increase, net of tax of $(2), $(28), $3 and $(24), respectively	(4		)	(42		)	4		(35		)
Reclassification of losses to net income, net of tax of $588, $446, $1,786 and $1,210, respectively	960			706			2,834		1,891
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
	956			664			2,838		1,856			829		948		1,654		1,882
Marketable securities:
Net fair value (decrease) increase, net of tax of $0, $0, $0 and $1, respectively	—			(1		)	—		1
Net fair value increase, net of tax of $0, $0, $0 and $0, respectively												1		—		1		—

Other comprehensive income	1,834			1,547			4,792		4,500			1,786		1,813		3,559		2,958
Comprehensive income	$	459,629		$	428,010		$	900,694	$	779,960		$	229,042	$	198,608	$	470,092	$	441,065

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

	Nine Months Ended Sept. 30						Six Months Ended June 30
	2016			2015			2017			2016
Operating activities
Net income	$	895,902		$	775,460		$	466,533		$	438,107
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	982,682			841,360			738,280			650,336
Conservation and demand side management program amortization	3,089			4,063			1,509			2,323
Nuclear fuel amortization	89,475			82,627			57,003			58,267
Deferred income taxes	479,100			429,091			309,239			252,889
Amortization of investment tax credits	(3,920		)	(4,151		)	(2,557		)	(2,613		)
Allowance for equity funds used during construction	(45,042		)	(40,728		)	(30,699		)	(27,843		)
Equity earnings of unconsolidated subsidiaries	(32,500		)	(24,360		)	(15,416		)	(22,799		)
Dividends from unconsolidated subsidiaries	34,502			29,434			23,507			22,910
Share-based compensation expense	29,872			29,765			31,892			24,454
Loss on Monticello life cycle management/extended power uprate project	—			129,463
Net realized and unrealized hedging and derivative transactions	3,307			18,808			217			3,903
Other	(266		)	—
Other, net							(2,441		)	(388		)
Changes in operating assets and liabilities:
Accounts receivable	(29,585		)	85,276			16,906			35,042
Accrued unbilled revenues	87,015			182,425			121,333			65,159
Inventories	(6,203		)	(47,659		)	65,433			81,880
Other current assets	80,566			72,445			(84,024		)	69,493
Accounts payable	50,526			(116,137		)	(52,349		)	27,805
Net regulatory assets and liabilities	3,911			116,068			1,498			34,264
Other current liabilities	(76,011		)	60,293			(190,184		)	(151,589		)
Pension and other employee benefit obligations	(96,350		)	(82,013		)	(140,479		)	(108,562		)
Change in other noncurrent assets	(11,815		)	2,374			(6,676		)	(6,363		)
Change in other noncurrent liabilities	(25,401		)	(53,982		)	(16,706		)	(21,649		)
Net cash provided by operating activities	2,412,854			2,489,922			1,291,819			1,425,026

Investing activities
Utility capital/construction expenditures	(2,186,483		)	(2,186,369		)	(1,473,793		)	(1,413,129		)
Proceeds from insurance recoveries	1,595			27,237			—			1,595
Allowance for equity funds used during construction	45,042			40,728			30,699			27,843
Purchases of investment securities	(390,031		)	(773,260		)	(368,266		)	(319,880		)
Proceeds from the sale of investment securities	327,378			753,924			350,448			262,321
Investments in WYCO Development LLC and other	(3,962		)	(832		)	(7,683		)	(2,170		)
Other, net	204			(676		)	(5,483		)	100
Net cash used in investing activities	(2,206,257		)	(2,139,248		)	(1,474,078		)	(1,443,320		)

Financing activities
Repayments of short-term borrowings, net	(480,000		)	(955,500		)
Proceeds from (repayments of) short-term borrowings, net							392,000			(399,000		)
Proceeds from issuance of long-term debt	1,632,642			1,627,190			394,046			1,337,430
Repayments of long-term debt	(580,167		)	(250,644		)	(250,397		)	(579,976		)
Proceeds from issuance of common stock	—			5,298
Purchase of common stock for settlement of equity awards	(2,810		)	—
Repurchases of common stock							(2,943		)	(789		)
Dividends paid	(507,817		)	(452,217		)	(355,250		)	(335,113		)
Net cash provided by (used in) financing activities	61,848			(25,873		)
Other							(18,291		)	(12,487		)
Net cash provided by financing activities							159,165			10,065

Net change in cash and cash equivalents	268,445			324,801			(23,094		)	(8,229		)
Cash and cash equivalents at beginning of period	84,940			79,608			84,476			84,940
Cash and cash equivalents at end of period	$	353,385		$	404,409		$	61,382		$	76,711

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(461,302	)	$	(424,878	)	$	(301,350	)	$	(293,954	)
Cash received for income taxes, net	61,245			57,632
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	$	221,155		$	284,864		$	233,250		$	252,370
Issuance of common stock for reinvested dividends and equity awards	17,527			39,169
Issuance of common stock for equity awards							18,505			13,497

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

	Sept. 30, 2016			Dec. 31, 2015			June 30, 2017			Dec. 31, 2016
Assets
Current assets
Cash and cash equivalents	$	353,385		$	84,940		$	61,382		$	84,476
Accounts receivable, net	754,248			724,606			759,378			776,289
Accrued unbilled revenues	567,852			654,867			608,499			729,832
Inventories	614,908			608,584			542,044			604,226
Regulatory assets	317,611			344,630			375,020			363,655
Derivative instruments	42,860			33,842			78,487			38,224
Deferred income taxes	195,303			140,219
Prepaid taxes	107,210			163,023			196,247			106,697
Prepayments and other	122,786			155,734			135,493			138,682
Total current assets	3,076,163			2,910,445			2,756,550			2,842,081

Property, plant and equipment, net	32,206,696			31,205,851			33,543,843			32,841,750

Other assets
Nuclear decommissioning fund and other investments	2,048,455			1,902,995			2,231,588			2,091,858
Regulatory assets	2,874,351			2,858,741			3,023,128			3,080,867
Derivative instruments	51,369			51,083			50,410			50,189
Other	67,716			32,581			255,470			248,532
Total other assets	5,041,891			4,845,400			5,560,596			5,471,446
Total assets	$	40,324,750		$	38,961,696		$	41,860,989		$	41,155,277

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	709,567		$	657,021		$	505,345		$	255,529
Short-term debt	366,000			846,000			784,000			392,000
Accounts payable	916,534			960,982			973,642			1,044,959
Regulatory liabilities	228,721			306,830			261,171			220,894
Taxes accrued	422,437			438,189			339,966			457,392
Accrued interest	155,005			166,829			175,849			172,901
Dividends payable	172,704			162,410			182,795			172,456
Derivative instruments	25,201			29,839			28,019			26,959
Other	457,803			490,197			439,917			503,953
Total current liabilities	3,453,972			4,058,297			3,690,704			3,247,043
							��
Deferred credits and other liabilities
Deferred income taxes	6,851,873			6,293,661			7,130,715			6,784,319
Deferred investment tax credits	64,499			68,419			60,659			63,216
Regulatory liabilities	1,367,557			1,332,889			1,386,675			1,383,212
Asset retirement obligations	2,703,396			2,608,562			2,849,532			2,782,229
Derivative instruments	154,650			168,311			136,255			148,146
Customer advances	216,978			228,999			190,640			195,214
Pension and employee benefit obligations	843,739			941,002			975,606			1,112,366
Other	277,561			261,756			225,215			223,965
Total deferred credits and other liabilities	12,480,253			11,903,599			12,955,297			12,692,667

Commitments and contingencies
Capitalization
Long-term debt	13,402,583			12,398,880			14,091,833			14,194,718
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,952,795 and 507,535,523 shares outstanding at Sept. 30, 2016 and Dec. 31, 2015, respectively	1,269,882			1,268,839
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
Additional paid in capital	5,898,896			5,889,106			5,881,475			5,881,494
Retained earnings	3,924,125			3,552,728			4,079,068			3,981,652
Accumulated other comprehensive loss	(104,961		)	(109,753		)	(106,795		)	(110,354		)
Total common stockholders’ equity	10,987,942			10,600,920			11,123,155			11,020,849
Total liabilities and equity	$	40,324,750		$	38,961,696		$	41,860,989		$	41,155,277

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

	Common Stock Issued								Retained Earnings				Accumulated Other Comprehensive Loss				Total Common Stockholders’ Equity			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 Sept. 30, 2016 and 2015									Retained Earnings
Balance at June 30, 2015	506,959		$	1,267,398		$	5,863,209		$	3,243,645			Accumulated Other Comprehensive Loss	$	(105,186	)		$	10,269,066
Three Months Ended June 30, 2017 and 2016																				Three Months Ended June 30, 2017 and 2016
Balance at March 31, 2016																				507,953	$	1,269,882	$	5,889,939		$	3,620,421		$	(108,608	)	$	10,671,634
Net income									426,463								426,463									196,795						196,795
Other comprehensive income													1,547				1,547												1,813			1,813
Dividends declared on common stock									(163,247		)						(163,247		)							(173,563		)				(173,563		)
Issuances of common stock	308		770			8,665											9,435			—	—		(187		)							(187		)
Share-based compensation						1,566											1,566						6,642									6,642
Balance at Sept. 30, 2015	507,267		$	1,268,168		$	5,873,440		$	3,506,861			$	(103,639	)		$	10,544,830
Balance at June 30, 2016																				507,953	$	1,269,882	$	5,896,394		$	3,643,653		$	(106,795	)	$	10,703,134

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	$	1,269,407	$	5,872,933		$	4,036,352		$	(108,581	)	$	11,070,111
Net income									457,795								457,795									227,256						227,256
Other comprehensive income													1,834				1,834												1,786			1,786
Dividends declared on common stock									(173,786		)						(173,786		)							(183,738		)				(183,738		)
Issuances of common stock	48		120			—											120
Purchase of common stock for settlement of equity awards	(48	)	(120		)	(2,021		)									(2,141		)
Share-based compensation						4,523			(3,537		)						986						8,542			(802		)				7,740
Balance at Sept. 30, 2016	507,953		$	1,269,882		$	5,898,896		$	3,924,125			$	(104,961	)		$	10,987,942
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

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XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (Continued) (amounts in thousands)	XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (Continued) (amounts in thousands)																		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
Nine Months Ended Sept. 30, 2016 and 2015
Balance at Dec. 31, 2014	505,733		$	1,264,333		$	5,837,330		$	3,220,958			$	(108,139	)		$	10,214,482
Net income									775,460							775,460
Other comprehensive income												4,500				4,500
Dividends declared on common stock									(489,557		)					(489,557		)
Issuances of common stock	1,534		3,835			18,874										22,709
Share-based compensation						17,236										17,236
Balance at Sept. 30, 2015	507,267		$	1,268,168		$	5,873,440		$	3,506,861		$	(103,639	)		$	10,544,830
																			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																			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		507,536		$	1,268,839		$	5,889,106		$	3,552,728		$	(109,753	)	$	10,600,920
Net income									895,902							895,902											438,107						438,107
Other comprehensive income												4,792				4,792														2,958			2,958
Dividends declared on common stock									(520,968		)					(520,968		)									(347,182		)				(347,182		)
Issuances of common stock	486		1,216			15,110										16,326			417		1,043			(3,942		)							(2,899		)
Purchase of common stock for settlement of equity awards	(69	)	(173		)	(2,810		)								(2,983		)
Repurchases of common stock																								(789		)							(789		)
Share-based compensation						(2,510		)	(3,537		)					(6,047		)						12,019									12,019
Balance at Sept. 30, 2016	507,953		$	1,269,882		$	5,898,896		$	3,924,125		$	(104,961	)		$	10,987,942
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

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XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of Xcel Energy Inc. and its subsidiaries as of ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015;~~2016; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2016~~2017 and ~~2015;~~2016; and its cash flows for the ~~nine~~six months ended ~~Sept.~~June 30, ~~2016~~2017 and ~~2015.~~2016. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after ~~Sept.~~June 30, ~~2016~~2017 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, ~~2015~~2016 balance sheet information has been derived from the audited ~~2015~~2016 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2015.~~2016. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2015,~~2016, filed with the SEC on Feb. ~~19, 2016.~~24, 2017. Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.


1.	Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2015,~~2016, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2.	Accounting Pronouncements

Recently Issued

Revenue Recognition — In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a new framework for the recognition of ~~revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive~~revenue. Xcel Energy expects its adoption will result in ~~exchange for goods and services. The new guidance also includes additional disclosure requirements~~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. The guidance is~~customers effective ~~for interim and annual reporting periods beginning after Dec. 15, 2017. Xcel Energy is currently evaluating~~Jan. 1, 2018, with the ~~impact of adopting ASU 2014-09 on its consolidated financial statements.~~

~~Presentation of Deferred Taxes —~~ ~~In November 2015, the FASB issued~~ ~~Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No 2015-17)~~, which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Other than the prescribed classification of all deferred tax assets and liabilities as noncurrent, Xcel Energy does not expect the implementation of ASU 2015-17 to have a materialcumulative impact on ~~its consolidated financial statements.~~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 ~~among other changes in accounting~~eliminates the available-for-sale classification for marketable equity securities and ~~disclosure requirements,~~also replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price ~~changes, and also eliminates the available-for-sale classification for marketable equity securities.~~changes. Under the new ~~guidance,~~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 isexpects 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 ~~evaluating~~classified as available-for-sale, will continue to be deferred to a regulatory asset, and that the ~~impact~~overall impacts of ~~adopting ASU 2016-01 on its consolidated financial statements.~~the Jan. 1, 2018 adoption will not be material.

~~Table of Contents~~

Leases — InIn February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which for lessees requires balance sheet recognition of right-of-use assets and lease liabilities for ~~all~~most leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, ~~2018, and early~~2018. Xcel Energy has not yet fully determined the impacts of implementation. However, adoption is ~~permitted.~~expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard. As such, agreements entered prior to Jan. 1, 2017 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 ~~is currently evaluating~~expects that similar agreements entered after Dec. 31, 2016 will generally qualify as leases under the ~~impact~~new standard, but has not yet completed its evaluation of ~~adopting ASU 2016-02 on its consolidated financial statements.~~certain other contracts, including arrangements for the secondary use of assets, such as land easements.

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~~Stock Compensation~~Presentation of Net Periodic Benefit Cost — InIn 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 ~~2016-09),~~No. 2017-07), which ~~amends existing~~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, ~~to simplify several aspects~~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 ~~presentation for share-based payment transactions, including~~that the ~~accounting for income taxes and forfeitures, as well as presentation~~impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of ~~cash flows.~~income. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, ~~2016, and early adoption is permitted. Xcel Energy does not expect the implementation of ASU 2016-09 to have a material impact on its consolidated financial statements.~~2017.

Recently Adopted

~~Consolidation~~Stock Compensation — —I ~~In February 2015,~~n March 2016, the FASB issued ~~Amendments~~Improvements to ~~the Consolidation Analysis,~~Employee Share-Based Payment Accounting, Topic ~~810~~718 (ASU No. ~~2015-02)~~, which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. Xcel Energy implemented the guidance on Jan. 1, 2016, and other than the classification of certain real estate investments held within the Nuclear Decommissioning Trust as non-consolidated variable interest entities, the implementation did not have a significant impact on its consolidated financial statements.

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

~~Fair Value Measurement~~— ~~In May 2015, the FASB issued~~ ~~Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07)~~2016-09), which ~~eliminates~~simplifies accounting and financial statement presentation for share-based payment transactions. The guidance requires that the ~~requirement~~difference between the tax deduction available upon settlement of share-based equity awards and the tax benefit accumulated over the vesting period be recognized as an adjustment to ~~categorize fair value measurements using a net asset value (NAV) methodology~~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 in the ~~fair value hierarchy. Xcel Energy implemented~~consolidated statements of cash flows for the ~~guidance on Jan. 1,~~years ended Dec. 31, 2016, 2015 and ~~the implementation did not have a material impact on its consolidated financial statements. For related disclosures, see Note 8 to the consolidated financial statements.~~2014.


3.	Selected Balance Sheet Data


(Thousands of Dollars)	Sept. 30, 2016			Dec. 31, 2015			June 30, 2017			Dec. 31, 2016
Accounts receivable, net
Accounts receivable	$	802,827		$	776,494		$	808,705		$	827,112
Less allowance for bad debts	(48,579		)	(51,888		)	(49,327		)	(50,823		)
	$	754,248		$	724,606		$	759,378		$	776,289

(Thousands of Dollars) Sept. 30, 2016 Dec. 31, 2015
Inventories
Materials and supplies $ 306,544
$ 290,690
Fuel 181,265
202,271
Natural gas 127,099
115,623
$ 614,908
$ 608,584

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(Thousands of Dollars)	June 30, 2017		Dec. 31, 2016
Inventories
Materials and supplies	$	321,426	$	312,430
Fuel	156,736		181,752
Natural gas	63,882		110,044
	$	542,044	$	604,226


(Thousands of Dollars)	Sept. 30, 2016			Dec. 31, 2015			June 30, 2017			Dec. 31, 2016
Property, plant and equipment, net
Electric plant	$	37,335,785		$	36,464,050		$	38,810,158		$	38,220,765
Natural gas plant	5,149,959			4,944,757			5,465,224			5,317,717
Common and other property	1,741,615			1,709,508			1,959,703			1,888,518
Plant to be retired ^(a)	36,852			38,249			17,820			31,839
Construction work in progress	1,844,525			1,256,949			1,571,362			1,373,380
Total property, plant and equipment	46,108,736			44,413,513			47,824,267			46,832,219
Less accumulated depreciation	(14,218,683		)	(13,591,259		)	(14,703,391		)	(14,381,603		)
Nuclear fuel	2,469,772			2,447,251			2,660,606			2,571,770
Less accumulated amortization	(2,153,129		)	(2,063,654		)	(2,237,639		)	(2,180,636		)
	$	32,206,696		$	31,205,851		$	33,543,843		$	32,841,750


^(a)	In the second half of 2017, PSCo expects to both early retire Valmont Unit 5 and convert 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, ~~2015~~2016 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

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

Federal ~~Audit~~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.

In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. ~~As of Sept. 30, 2016, the~~The IRS ~~had~~has proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 ~~and 2014 claims and the anticipated claim for 2015. In the fourth quarter of~~through 2015 ~~the IRS forwarded the issue to the Office of Appeals (Appeals).~~claims. In 2016 the IRS audit team and Xcel Energy presented their cases to the Office of Appeals; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns, following extensions, expires in June 2017. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of the IRS’s proposed adjustment of the carryback claims.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. AsIn the second quarter of ~~Sept. 30, 2016,~~2017, the IRS ~~had not~~ proposed ~~any material adjustments~~an adjustment to tax ~~years~~year 2012 that may impact Xcel Energy’s net operating loss (NOL) and ~~2013.~~effective tax rate (ETR). Xcel Energy is evaluating the IRS’ proposal and the outcome and timing of a resolution is uncertain.

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 ~~Sept.~~June 30, ~~2016,~~2017, 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 ~~February~~2016, Minnesota began an audit of years 2010 through 2014. As of June 30, 2017, Minnesota had not proposed any adjustments;

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

material adjustments;

In ~~June 2016, Minnesota began an audit of years 2010 through 2014. As of Sept. 30, 2016, Minnesota had not proposed any adjustments.~~

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

As of ~~Sept.~~June 30, ~~2016,~~2017, there were no other state income tax audits in progress.

~~Table of Contents~~

Unrecognized ~~Tax~~ Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ~~effective tax rate (ETR).~~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)	Sept. 30, 2016		Dec. 31, 2015		June 30, 2017		Dec. 31, 2016
Unrecognized tax benefit — Permanent tax positions	$	27.7	$	25.8	$	30.8	$	29.6
Unrecognized tax benefit — Temporary tax positions	103.1		94.9		106.6		104.1
Total unrecognized tax benefit	$	130.8	$	120.7	$	137.4	$	133.7

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


(Millions of Dollars)	Sept. 30, 2016			Dec. 31, 2015			June 30, 2017			Dec. 31, 2016
NOL and tax credit carryforwards	$	(42.1	)	$	(36.7	)	$	(47.4	)	$	(43.8	)

It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals and audit progress, the 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 ~~$58~~$61 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. ~~The payables~~A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits ~~at Sept. 30, 2016 and Dec. 31, 2015 were not material.~~ 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	)

No amounts were accrued for penalties related to unrecognized tax benefits as of ~~Sept.~~June 30, ~~2016~~2017 or Dec. 31, ~~2015.~~2016.


5.	Rate Matters

Except to the extent noted below, the circumstances set forth in Note 12 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2015~~2016 and in Note 5 to Xcel Energy Inc.’s Quarterly ~~Reports~~Report on

Form 10-Q for the quarterly ~~periods~~period ended March 31, ~~2016 and June 30, 2016,~~2017, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

NSP-Minnesota

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

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

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

~~In December 2015,~~June 2017, the MPUC ~~approved interim rates for 2016.~~

~~Settlement Agreement~~

~~In August 2016,~~issued a written order. NSP-Minnesota ~~reached a settlement with~~estimates the ~~Minnesota Department of Commerce (DOC), Xcel Large Industrials,~~total rate increase to be approximately $245 million over the Minnesota Chamber of Commerce, the Commercial Group, the Suburban Rate Authority, the City of Minneapolis, the Industrial, Commercial, and Institutional Group, and the Energy CENTS Coalition, which resolves all revenue requirement issues in dispute. The settlement agreement requires the approval of the MPUC.

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four-year period covering 2016-2019.

Key ~~terms of the settlement are listed below:~~terms:

~~The agreement reflects a four-year~~Four-year period covering 2016-2019;

~~The stated revenue increases in the table below are based on the DOC’s sales forecast;~~

Annual sales ~~true-up to weather-normalized actuals all years, all classes:~~true-up;

~~2016 weather-normalized actuals used to set final 2016 rates, no cap;~~

~~2016-2019 full decoupling for decoupled classes (residential, non-demand metered commercial) with 3 percent cap; and~~

~~2017-2019 annual true-up for non-decoupled classes with 3 percent cap.~~

~~An ROE~~Return on equity (ROE) of 9.2 percent and an equity ratio of 52.5 percent;

~~The nuclear~~Nuclear related costs ~~in this rate case~~ will not be considered provisional;

Continued use of all existing riders, ~~during the four-year term,~~ however no new riders ~~or legislative additions would~~may be utilized during the four-year term;

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

~~A four-year stay out~~Four-year stay-out provision for rate ~~cases.~~cases;

~~Compliance steps recommended by the settling parties to implement the settlement:~~

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

~~A capital~~Capital expenditure true-up mechanism for 2016-2019.

(Millions of Dollars, incremental) 2016 2017 2018 2019 Total
Settlement revenues ^(a)
$ 74.99
$ 59.86
$ —
$ 50.12
$ 184.97
NSP-Minnesota’s sales forecast ^(b)
37.40
—
—
—
37.40
Total rate impact $ 112.39
$ 59.86
$ —
$ 50.12
$ 222.37


^(a)	~~The settlement revenue increase reflects an increase of 2.47 percent in 2016; 1.97 percent in 2017; 0 percent in 2018 and 1.65 percent in 2019.~~


^(b)	The table reflects the estimated rate impact of this agreement, using NSP-Minnesota’s original sales forecast as filed in the Minnesota rate case. The settlement agreement includes a provision to true-up estimated sales to the actual sales for 2016.

~~The revised schedule for the Minnesota rate case is listed below:~~



(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

~~Administrative law judge (ALJ) report — March 3, 2017; and~~

~~MPUC decision — June 2017.~~

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A current liability that is consistent with the settlement and represents NSP-Minnesota’s best estimate of a refund obligation for 2016 associated with interim rates was recorded as of Sept. 30, 2016.

~~NSP-Minnesota – Gas Utility Infrastructure Costs (GUIC) Rider~~ —In August 2016, the MPUC approved NSP-Minnesota’s request to recover approximately $15.5 million in natural gas infrastructure costs through the GUIC Rider, based on NSP-Minnesota’s proposed capital structure and a ROE of 9.64 percent. Recovery was approved for the 15-month period from January 2016 to March 2017.

Annual Automatic Adjustment ~~(AAA)~~ of Fuel Clause Charges — — In ~~June~~ 2016, the ~~DOC~~Minnesota Department of Commerce (DOC) recommended the MPUC should hold utilities responsible for incremental costs of replacement power incurred due to unplanned outages at nuclear facilities under certain circumstances. ~~The DOC’s recommendation could impact~~In May 2017, the MPUC voted to disallow approximately $4.4 million of replacement ~~power cost recovery~~energy costs for the Prairie Island (PI) nuclear facility outages allocated to the Minnesota jurisdiction ~~during~~in 2015. This disallowance was recognized in the ~~AAA fiscal~~second quarter of 2017. The MPUC issued a written order in July 2017. In addition, 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.

NSP-Wisconsin

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

Wisconsin 2018 Electric and Natural Gas Rate Case— In May 2017, NSP-Wisconsin filed a request with the PSCW to increase electric rates by $24.7 million, or 3.6 percent, and natural gas rates by $12.0 million, or 10.1 percent, effective January 2018. The rate filing is based on a 2018 forecast test year, ~~ended~~a ROE of 10.0 percent, an equity ratio of 52.53 percent and a forecasted average net investment rate base of approximately $1.2 billion for the electric utility and $138.4 million for the natural gas utility.

Key dates 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.

PSCo

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

Multi-Year Natural Gas Rate Case — In June ~~30,~~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. ~~NSP-Minnesota expects~~The request, detailed below, is based on forecast test years, a ~~MPUC decision~~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

^(a)The roll-in of PSIA rider revenue 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 ~~mid-2017.~~November 2017. The recovery of new, incremental PSIA related investments in 2019 and 2020 are included in the base rate request.

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

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 — 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 ~~2013, NSP-Minnesota completed~~July 2017, the ~~Monticello life cycle management (LCM)/extended power uprate (EPU) project.~~CPUC approved PSCo’s 2016 earnings test, which does not result in any earnings sharing. The ~~multi-year project extended the life~~current estimate of the ~~facility and increased~~2017 earnings test, based on annual forecasted information, did not result in the capacity from 600 to 671 megawatts (MW) in 2015. The Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes allowance for funds used during construction (AFUDC). In 2008, project expenditures were initially estimated at approximately $320 million, excluding AFUDC.recognition of a liability as of June 30, 2017.

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

~~NSP-Wisconsin~~SPS

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

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

The electric rate request is for the limited purpose of recovering increases in (1) generation and transmission fixed charges and fuel and purchased power expenses related to the interchange agreement with NSP-Minnesota, and (2) costs associated with forecasted average rate base of $1.188 billion in 2017.

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

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

In August 2016, the PSCW Staff (Staff) and the intervenors filed their direct testimony in the case. The Staff recommended an electric rate increase of $19.5 million, or 2.7 percent and a natural gas rate increase of $4.8 million, or 3.9 percent. The Staff adjustments reflect revisions to previously forecasted rate base as well as fuel and purchased power expense. The Staff’s recommended rate increase also encompasses the PSCW’s July 2016 decision to remove the $9.5 million fuel refund credit from the rate case and refund that amount directly to customers in 2016. Adjusting for the treatment of the fuel refund, the Staff’s recommendation is $7.4 million less than NSP-Wisconsin’s request.

On Oct. 26, 2016, the PSCW verbally approved an electric rate increase of approximately $22.5 million, or 3.2 percent, and a natural gas rate increase of $4.8 million, or 3.9 percent. The difference between the Staff’s recommendation and the PSCW’s approved electric increase is attributable to an increase in forecasted fuel and purchased power expense. Consistent with long-standing PSCW policy, these costs were updated prior to the PSCW’s decision to reflect current market forecasts. The PSCW approved NSP-Wisconsin’s requested natural gas rate increase consistent with the Staff’s recommendation.

~~The major components of the retail electric rate increase, the Staff’s recommendation, and the PSCW’s approval are summarized below:~~

Electric Rate Request (Millions of Dollars) NSP-Wisconsin Request Staff Recommendation Final Decision
Rate base investments $ 11.0
$ 7.6
7.6
Generation and transmission expenses (excluding fuel and purchased power) ^(a)
6.8
6.1
6.1
Fuel and purchased power expenses 11.0
7.7
10.7
Subtotal 28.8
21.4
24.4
2015 fuel refund ^(b)
(9.5 ) —
—
Department of Energy settlement refund (1.9 ) (1.9 ) (1.9 )
Total electric rate increase $ 17.4
$ 19.5
$ 22.5

^(a)

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

^(b)

In July 2016, the PSCW required NSP-Wisconsin to return the 2015 fuel refund directly to customers, rather than using it to offset the proposed 2017 rate increase, as originally proposed by NSP-Wisconsin. This decision, when combined with the increase in forecasted fuel and purchased power expense, effectively increases NSP-Wisconsin’s requested electric rate increase to $29.9 million, or 4.2 percent.

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~~NSP-Wisconsin anticipates a final written order later this year, with new rates effective on Jan. 1, 2017.~~

~~SPS~~

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

Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of ~~$64.8 million, which it subsequently revised to~~ $42.1 million. In 2015, the PUCT approved an overall rate decrease of approximately $4.0 million, net of rate case expenses. In April 2016, SPS filed an appeal, with the Texas State District Court, of 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. ~~The hearing in~~In March 2017, the ~~appeal is scheduled for February 2017.~~Travis County District Court denied SPS’ appeal. In April 2017, SPS appealed the District Court’s decision to the Court of Appeals.

Texas 2016 ~~Electric Rate Case~~Transmission Cost Recovery Factor (TCRF) Application — In February ~~2016,~~2017, SPS filed ~~a retail electric, non-fuel rate case in Texas~~ with ~~each of its Texas municipalities and~~ the PUCT ~~requesting an overall increase in~~to recover additional annual ~~base rate~~ revenue of approximately ~~$71.9~~$16.1 million through its TCRF, or ~~14.4~~1.8 percent. The filing iswas based ~~on a historic test year (HTY) ended Sept. 30, 2015, a requested ROE of 10.25 percent, an electric rate base~~upon capital transmission additions made during 2016. In June 2017, the PUCT approved TCRF rider recovery of approximately ~~$1.7 billion, and an equity ratio of 53.97 percent. In SPS’ required update filing in April 2016, SPS revised its requested rate increase to $68.6 million.~~

~~Pursuant to legislation passed in Texas in 2015, the final rates established in the case will be~~$14.4 million effective ~~retroactive to July 20, 2016.~~

In August 2016, several intervenors filed direct testimony in response to SPS’ rate request, including: PUCT Staff (Staff), the Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), Texas Industrial Energy Consumers (TIEC), and the State of Texas’ agencies.

The Staff recommended a rate increase of approximately $32.9 million, based on a ROE of 9.30 percent and an equity ratio of 51 percent. The Staff’s proposed rate increase reflects imputed revenues for power factor adjustment charges and weather normalization;

~~AXM recommended a rate increase of approximately $25.2 million, based on a ROE of 9.40 percent and an equity ratio of 51 percent; and~~

The other intervenors did not present a complete revenue requirement analysis. The majority of the direct testimony focused on specific cost allocation and rate design issues. However, OPUC and TIEC recommended ROEs of 9.20 percent and 9.15 percent, respectively.

In October 2016, SPS and various parties reached an agreement in principle in the Texas rate case. SPS and the parties are documenting the settlement, and expect to file with the PUCT in the fourth quarter of 2016. Any settlement would require approval of the PUCT, with a decision expected by the end of 2016 or early 2017.immediately.

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

New Mexico ~~2015~~2016 Electric Rate Case —In ~~October 2015,~~November 2016, SPS filed an electric rate case with the NMPRC seeking an increase in ~~non-fuel~~ base rates of ~~$45.4 million. The proposed~~approximately $41.4 million, representing a total revenue increase ~~would be offset by a decrease in base fuel revenue~~ of approximately ~~$21.1 million.~~10.9 percent. The rate filing ~~was~~is based on ~~a June 30, 2015 HTY adjusted for known and measurable changes,~~ a requested ROE of ~~10.25~~10.1 percent, an equity ratio of 53.97 percent, an electric rate base of approximately ~~$734~~$832 million and ~~an equity ratio of 53.97 percent.~~

In August 2016, the NMPRC approved a black-box stipulation that resulted in a non-fuel base rate increase of $23.5 million and a decrease in base fuel revenue of approximately $21.1 million. The decrease in base fuel revenue will be reflected in adjustments to the fuel and purchased power cost adjustment clause.

~~SPS plans to file another base rate case in November 2016 utilizing~~ 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, 2017, the NMPRC dismissed SPS’ rate case. On May 15, 2017, SPS filed a notice of appeal to the New Mexico Supreme Court. A decision from the New Mexico Supreme Court is not expected until the second or third quarter of 2018.

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

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

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In December 2015, an ~~ALJ initial decision~~administrative law judge (ALJ) recommended the FERC approve a base ROE of 10.32 percent ~~which~~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 ~~upheld~~ROE policy adopted in a June 2014 order (Opinion 531). The FERC approved the ALJ recommended 10.32 percent base ROE in an order issued ~~on Sept. 28,~~in September 2016. This ROE iswould be applicable for the 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 iswould be 10.82 percent, ~~which includes~~including a ~~previously approved~~ 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 ~~region~~ ROE from 12.38 percent to 8.67 percent prior to any adder was filed ~~which~~with the FERC, ~~set for hearings,~~ resulting in a second period of potential refund from Feb. 12, 2015 to May 11, 2016. The MPUC, the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission and the DOC joined a joint complainant/intervenor initial brief recommending an ROE of approximately 8.81 percent. FERC staff recommended a ROE of 8.78 percent. The MISO TOs recommended a ROE of 10.92 percent. OnIn June ~~30,~~ 2016, the ALJ recommended a ROE of 9.7 percent, applying the ~~midpoint~~methodology adopted by the FERC in Opinion 531. A final FERC decision on the second ROE complaint was expected later in 2017, but 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 ~~upper half~~second ROE complaint. The MISO TOs are evaluating the impact of the ~~discounted cash flow range. A FERC decision is expected in 2017.~~D.C. Circuit ruling on the November 2013 and February 2015 ROE complaints.

As of ~~Sept.~~June 30, ~~2016,~~2017, NSP-Minnesota has ~~recognized a current liability~~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, as well as~~order. NSP-Minnesota has also recognized a current refund liability ~~representing~~consistent with the best estimate of the final ROE for the ~~second~~Feb. 12, 2015 to May 11, 2016 complaint period.

~~Southwest Power Pool, Inc. (SPP) Open Access Transmission Tariff (OATT) Upgrade Costs~~ ~~— Under the SPP OATT, costs~~

Table of participant-funded, or “sponsored,” transmission upgrades may be recovered, in part, from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP OATT has allowed SPP to collect charges since 2008, but to date SPP has not charged its customers any amounts attributable to these upgrades. Contents

In April 2016, SPP filed a request with the FERC for a waiver that would allow SPP to recover the charges not billed since 2008. The FERC approved the waiver request in July 2016. SPS and certain other parties requested rehearing of the FERC order. In September 2016, SPP provided further information regarding additional costs, primarily due to the system-wide claw back of point to point revenues previously distributed to SPS and other entities. Amounts due to SPP are expected to be paid over a five-year period commencing November 2016 under an optional payment plan that was approved by the FERC in September 2016 and elected by SPS in October 2016. Based on SPP’s most recent calculation in October 2016, estimated costs would be approximately $12 million to $14 million, and SPS anticipates these costs would be recoverable through regulatory mechanisms.


6.	Commitments and Contingencies

Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 12, 13 and 14 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2015,~~2016, and in Notes 5 and 6 to the

consolidated financial statements included in Xcel Energy Inc.’s Quarterly ~~Reports~~Report on Form 10-Q for the quarterly ~~periods~~period ended March 31, ~~2016 and June 30, 2016,~~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.

~~Purchased Power Agreements (PPAs)~~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 ~~approximate~~lyapproximately 3,537 ~~MW and 3,698 MW~~megawatts (MW) of capacity under long-term PPAs as of ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015,~~2016, 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.

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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 ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015,~~2016, 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)	Sept. 30, 2016		Dec. 31, 2015		June 30, 2017		Dec. 31, 2016
Guarantees issued and outstanding	$	19.0	$	12.5	$	18.3	$	18.8
Current exposure under these guarantees	0.1		0.1		—		0.1
Bonds with indemnity protection	43.0		41.3		49.4		43.0

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 ~~MGP~~Manufactured Gas Plant (MGP) Site — NSP-Wisconsin ~~has been~~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 (the Sediments).~~park.

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In 2012, ~~under a settlement agreement with the United States Environmental Protection Agency (EPA),~~ NSP-Wisconsin agreed to remediate the Phase I Project Area (which includes the Upper Bluff and Kreher Park areas of the Site)~~. The current cost estimate for~~, under a settlement agreement with the ~~cleanup of the Phase I Project Area is approximately $71.4 million, of which approximately $52.6 million has been spent.~~

United States Environmental Protection Agency (EPA).

NSP-Wisconsin performed a wet dredge pilot study in ~~the summer of~~ 2016 and demonstrated that a wet dredge remedy can meet the performance standards for remediation of the ~~Sediments.~~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. ~~Settlement negotiations are ongoing between~~In January 2017, NSP-Wisconsin agreed to remediate the ~~EPA and NSP-Wisconsin regarding the performance of the full scale cleanup of the Sediments. If~~Sediments, under a ~~court-approved~~ settlement ~~can be reached~~agreement with the ~~EPA,~~EPA. The settlement was approved by the U.S. District Court for the Western District of Wisconsin. NSP-Wisconsin ~~anticipates~~has initiated field activities to perform a full scale wet dredge remedy of the Sediments ~~could be performed beginning as early as~~in 2017, ~~and potentially conclude by~~with performance of restoration activities in 2018.

The current cost estimate for the entire site is approximately $160.0 million, of which approximately $113.2 million has been spent. At ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015,~~2016, NSP-Wisconsin had recorded a total liability of ~~$84.6~~$46.8 million and ~~$94.4~~$64.3 million, respectively, for the entire site. NSP-Wisconsin’s potential liability, the actual cost of remediation and the timing of expenditures are subject to change. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the remediation cost.

NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation costs as a regulatory asset. The PSCW has ~~consistently~~ authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Site. In 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 ~~April 2016,~~May 2017, NSP-Wisconsin filed a ~~limited~~ natural gas rate case ~~for~~which included recovery of additional expenses associated with remediating the Site. If approved, the annual recovery of MGP clean-up costs would increase from ~~$7.6 million in 2016 to~~ $12.4 million in ~~2017.~~

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2017 to $18.1 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 ~~at that time~~ and commenced an investigation of the historic MGP and adjacent properties (the Fargo MGP Site). ~~Based on the investigation that concluded in the third quarter of 2016,~~ NSP-Minnesota has recommended that targeted source removal of impacted soils and historic MGP infrastructure should be ~~performed, subject to further input from the~~performed. The North Dakota Department of Health approved NSP-Minnesota’s proposed cleanup plan in January 2017. The timing and final scope of remediation is dependent on whether reasonable access is provided to NSP-Minnesota to perform and implement the ~~City of Fargo, N.D., current property owners and other stakeholders.~~

approved cleanup plan. 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 ~~November 2016 to allow NSP-Minnesota time to investigate site conditions. NSP-Minnesota intends to seek an additional stay of the litigation.~~September 2017.

As of ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015,~~2016, NSP-Minnesota had recorded a liability of ~~$12.2~~$16.4 million and ~~$2.7~~$11.3 million, respectively, for the Fargo MGP ~~Site, with the increase due to~~Site. The current cost estimate for the remediation ~~activities proposed by NSP-Minnesota.~~of the site is approximately $23.0 million, of which approximately $6.6 million has been spent. In December 2015, the ~~NDPSC~~North Dakota Public Service Commission (NDPSC) approved NSP-Minnesota’s request to defer costs associated with the Fargo MGP Site, resulting in deferral of all investigation and response costs with the exception of approximately 12 percent allocable to the Minnesota jurisdiction. Uncertainties related to the liability recognized include obtaining access ~~and approvals from stakeholders~~ to perform the ~~proposed~~approved remediation (including 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.

Other MGP and Landfill Sites — Xcel Energy is currently involved in investigating and/or remediating several other MGP and landfill sites. Xcel Energy has identified ten 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 and are under current investigation and/or remediation. At some or all of these sites, there are other parties that may have responsibility for some portion of any remediation. Xcel Energy anticipates that the majority of the investigation or remediation at these sites will continue through at least 2018. Xcel Energy had accrued $2.9 million and $2.0 million for these sites at June 30, 2017 and Dec. 31, 2016, respectively. There may be insurance recovery and/or recovery from other PRPs to offset any costs incurred. Xcel Energy anticipates that any significant amounts incurred will be recovered from customers.

Environmental Requirements

Water and Waste

~~Coal Ash Regulation~~Federal Clean Water Act (CWA) Waters of the United States Rule — ~~Xcel Energy’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste.~~ In ~~April~~ 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule ~~regulating~~that significantly expands the ~~management~~types of water bodies regulated under the CWA and ~~disposal~~broadens the scope of ~~coal combustion byproducts (coal ash) as a nonhazardous waste. Under the~~waters subject to federal jurisdiction. The final rule ~~Xcel Energy’s~~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 ~~to manage~~ and ~~dispose of coal ash has not significantly increased.~~

expanding permitting and reporting requirements. In October 2015, ~~industry and environmental non-governmental organizations sought judicial review of~~ the ~~final rule. In June 2016, the United States~~U.S. Court of Appeals for the ~~District~~Sixth Circuit issued a nationwide stay of ~~Columbia Circuit (D.C. Circuit)~~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 ~~remanding~~requiring the EPA and ~~vacating certain elements~~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 rule as a result of partial settlements with these parties. Oral arguments are expected to be heard in early 2017 and a final decision is anticipated in the first half of 2017. Until a final decision is reached in the case, it is uncertain whether the litigation or partial settlements will have any significant impact on results of operations, financial position or cash flows on Xcel Energy.U.S.”

Air

~~Cross-State Air Pollution Rule (CSAPR)~~Greenhouse Gas (GHG) Emission Standard for Existing Sources (Clean Power Plan or CPP) — ~~CSAPR addresses long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO~~₂~~) and nitrogen oxide (NOx) from utilities in~~In 2015, the ~~eastern half of the United States using an emissions trading program. For Xcel Energy,~~EPA issued its final rule for existing power plants. Among other things, the rule ~~applies in Minnesota, Wisconsin~~requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and ~~Texas.~~final (2030 and thereafter) emission performance targets.

~~CSAPR~~The CPP was adopted to address interstate emissions impacting downwind states’ attainment of the 1997 ozone National Ambient Air Quality Standard (NAAQS) and the 1997 and 2006 particulate NAAQS. As the EPA revises the NAAQS, it will consider whether to make any further reductions to CSAPR emission budgets and whether to change which states are includedchallenged by multiple parties in the ~~emissions trading program.~~D.C. Circuit Court. In ~~December 2015,~~February 2016, the ~~EPA proposed adjustments to CSAPR emission budgets which address attainment of~~U.S. Supreme Court issued an order staying the ~~more stringent 2008 ozone NAAQS.~~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 ~~adopted~~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 ~~final~~proposed rule ~~that reduced~~to the ozone season emission budget for NOx in Texas by approximately 22 percent, which is expected to lead to increased costs to purchase emission allowances. Xcel Energy does not anticipate these increased costs to purchase emission allowances will have a material impact onOffice of Management and Budget entitled “Review of the ~~results of operations, financial position or cash flows.~~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. ~~In 2005, the EPA amended the best available retrofit technology~~The Best Available Retrofit Technology (BART) requirements of ~~its~~the EPA’s regional haze rules ~~which~~ 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 SOSulfur Dioxide (SO₂₂₎, ~~NOx~~Nitrogen Oxide (NOx) and PMparticulate 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, ~~CSAPR.~~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.

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Actions affecting Harrington Units:Texas developed a ~~state implementation plan~~State Implementation Plan (SIP) that finds the CAIR equal to BART for electric generating ~~units (EGUs).~~units. As a result, no additional controls beyond CAIR compliance would be required. In ~~December~~ 2014, the EPA proposed to approve the BART portion of the 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’s~~Circuit Court’s remand of the Texas SO₂emission budgets. In March 2016, the EPA requested information under the Clean Air Act related to EGUs at SPS’ plants. SPS identified Harrington Units 1 and 2, Jones Units 1 and 2, Nichols Unit 3 and Plant X Unit 4 as BART-eligible units. These units will be evaluated based on their impact on visibility. Additional emission control equipment under the EPA’s BART guidelines for PM, SO₂ and NOx could be required if a unit is determined to “cause or contribute” to visibility impairment. SPS cannot evaluate the impact of additional emission controls until the EPA concludes its evaluation of BART. In June 2016, the EPA issued a memorandum which allows Texas to voluntarily adopt the CSAPR emission budgets limiting annual SO₂ and NOx emissions and rely on those emission budgets to satisfy Texas’ BART obligations under the regional haze rules. ~~It is not yet known whether the~~The Texas Commission on Environmental Quality ~~(TCEQ) intends to utilize~~has not utilized this option. ~~If Texas does not opt into the CSAPR rule, the~~The EPA ~~is expected to issue~~then published a proposed rule in ~~December 2016~~January 2017 that could ~~impact~~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.

~~In December 2014, the EPA proposed to disapprove portions of the SIP and instead adopt a federal implementation plan (FIP).~~Actions affecting Tolk units: In January 2016, the EPA adopted a final rule establishing a ~~FIP~~federal implementation plan for the state of Texas, which imposed SO₂ emission limitations that reflect the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be approximately $600 million. ~~In March 2016,~~ SPS appealed the EPA’s decision and ~~asked for~~requested a stay of the final ~~rule while it is being reviewed. In July 2016, the~~rule. The United States Court of Appeals for the Fifth Circuit (Fifth Circuit) granted the stay ~~motion~~ and decided that ~~the Fifth Circuit, not the D.C. Circuit, is~~they are the appropriate venue for this case. In ~~addition, SPS filed a petition with~~March 2017, the Fifth Circuit remanded the rule to the EPA ~~requesting~~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 ~~final~~ rule. SPS believes these costs or the costs of alternative cost-effective generation would be recoverable through regulatory mechanisms if required, and therefore does not expect a material impact on results of operations, financial position or cash flows.

~~Implementation of the NAAQS for SO~~₂ ~~— The EPA adopted a more stringent NAAQS for SO~~₂ in 2010. The EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant and SPS’ Tolk and Harrington plants. The Pawnee plant recently installed an SO₂ ~~scrubber and the Tolk and Harrington Plants utilize low sulfur coal to reduce SO~~₂ emissions. In June 2016, the EPA issued final designations which found the area near the Tolk plant to be meeting the NAAQS and the areas near the Harrington and Pawnee plants as “unclassifiable.” The area near the Harrington plant is to be monitored for three years and a final designation is expected to be made by December 2020. It is ~~anticipated~~likely that Texas and other affected entities including SPS would continue to challenge the ~~area near the Pawnee plant will be able~~determinations to ~~show compliance~~date. The risk of these controls being imposed along with the ~~NAAQS through air dispersion modeling performed by the Colorado Department~~risk of ~~Public Health and Environment.~~

~~If an area is designated nonattainment in 2020, the states will need to evaluate all SO~~₂ ~~sources in the area. The state would then submit an implementation plan, which would be due by 2022, designed to achieve the NAAQS by 2025. The TCEQ could require additional SO~~₂ controls at Harrington as part of such a plan. The areas near the remaining Xcel Energy power plants will be evaluated in the next designation phase, ending December 2017. The remaining plants, PSCo’s Comanche and Hayden plants along with NSP-Minnesota’s King and Sherco plants, utilize scrubbers to control SO₂ ~~emissions. Xcel Energy cannot evaluate the impacts until the designation of nonattainment areas is made, and any required state plans are developed. Xcel Energy believes that should SO~~₂ control systems be required for a plant, compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.

In light of the continuing development of environmental regulatory requirements, as well as the more favorable long term outlook for alternative resources, SPS is undertaking analysis to determine the most cost-effective means to meet the needs of its customers, given a low natural gas price environment, the need to make additional investments to provide cooling water to Tolk have caused SPS to seek to decrease the remaining depreciable life of the Tolk ~~facility and the potential need to make major investments in air pollution control equipment.~~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

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

In May 2015, the FERC issued an order rejecting the City’s claim that any of the sales made resulted in an excessive burden and concluded that the City failed to establish a causal link between any contracts and any claimed unlawful market activity. In February 2016, the City appealed this decision to the Ninth Circuit. This appeal is pending review by the Ninth Circuit.

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

In October 2016, a settlement was reached that resolves all outstanding claims between and among the City and the respondents, including PSCo. Settlement terms required PSCo to pay the City $15,000 and the City to withdraw its pending appeal with the Ninth Circuit. This brings this matter to a close.

Gas Trading Litigation — e prime, inc. (e prime) is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Thirteen lawsuits were commenced against e prime and Xcel Energy (and NSP-Wisconsin, in two instances) between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices.

The cases were consolidated in U.S. District Court in Nevada. Five of the cases have since been settled and seven ~~have been dismissed. One~~remain active, which includes one multi-district litigation (MDL) matter ~~remains and it consists~~consisting of a Colorado class (Breckenridge), a Wisconsin class (NSP-Wisconsin), a Kansas class, and two other cases identified as “Sinclair Oil” and “Farmland.” In ~~May~~November 2016, the MDL judge ~~granted summary judgment dismissing defendants from the Farmland lawsuit.~~dismissed e prime and Xcel Energy ~~have~~from the Farmland lawsuit, and Farmland has appealed the dismissal. Motions for summary judgment were filed ~~a motion seeking clarification that this order includes them. This motion is currently pending and is expected to be heard in December 2016. The~~by defendants, including e prime, ~~defendants filed a~~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 plaintiffs motions for class certification in the other lawsuits. The U.S. District Court did not grant e prime’s summary judgment ~~motion~~motions in the Wisconsin or Colorado ~~class lawsuit (Breckenridge)~~cases. There are currently additional motions brought by e prime for reconsideration and ~~oppositions to class certifications~~summary judgment pending in ~~all~~ the ~~class actions, which is also expected to be heard in December 2016. Trial dates are not expected to occur prior to early 2017.~~U.S. District Court. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote.

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Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in Denver State Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements entered into by PSCo and various developers. The dispute involves ~~assigned interests in those~~ claims by over fifty developers. In May 2016, the district court granted PSCo’s motion to dismiss the lawsuit, concluding that jurisdiction over this dispute resides with the ~~Colorado Public Utilities Commission (CPUC).~~CPUC. In June 2016, DRC appealed the district court’s dismissal of the lawsuit, and the Colorado Court of Appeals affirmed the lower court decision in favor of PSCo. In July 2017, DRC filed a ~~notice of appeal. DRC filed its opening brief on Oct. 20, 2016 and PSCo’s answer brief~~petition to appeal the decision with the Colorado Supreme Court. It is ~~due Nov. 24, 2016.~~uncertain whether the Colorado Supreme Court will grant the petition. DRC also brought a 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 did 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.

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


(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2016			Year Ended Dec. 31, 2015			Three Months Ended June 30, 2017			Year Ended Dec. 31, 2016
Borrowing limit	$	2,750		$	2,750		$	2,750		$	2,750
Amount outstanding at period end	366			846			784			392
Average amount outstanding	477			601			778			485
Maximum amount outstanding	609			1,360			1,247			1,183
Weighted average interest rate, computed on a daily basis	0.77		%	0.48		%	1.28		%	0.74		%
Weighted average interest rate at period end	0.77			0.82			1.49			0.95

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 ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015,~~2016, there were ~~$19~~$14 million and ~~$29~~$19 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 ~~facility capacity.~~facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

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At ~~Sept.~~June 30, ~~2016,~~2017, 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	$	362	$	638	$	1,000	$	549	$	451
PSCo	700		3		697		700		3		697
NSP-Minnesota	500		11		489		500		91		409
SPS	400		5		395		400		109		291
NSP-Wisconsin	150		4		146		150		46		104
Total	$	2,750	$	385	$	2,365	$	2,750	$	798	$	1,952


^(a)	These credit facilities expire in June 2021.


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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding at ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015.~~2016.

~~Amended Credit Agreements~~ - In June 2016, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS entered into amended five-year credit agreements with a syndicate of banks. The total borrowing limit under the amended credit agreements remained at $2.75 billion. The amended credit agreements have substantially the same terms and conditions as the prior credit agreements with the following exceptions:

~~The maturity extended from October 2019 to June 2021.~~

The Eurodollar borrowing margins on these lines of credit were reduced to a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.

The commitment fees, calculated on the unused portion of the lines of credit, were reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

Xcel Energy Inc., NSP-Minnesota, PSCo and SPS 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.

Long-Term Borrowings

~~During the nine months ended Sept. 30, 2016, Xcel Energy Inc. and its utility subsidiaries completed the following bond issuances:~~

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

~~In May, NSP-Minnesota issued $350 million of 3.6 percent first mortgage bonds due May 15, 2046;~~

~~In June, PSCo issued $250 million of 3.55~~3.80 percent first mortgage bonds due June 15, ~~2046; and~~

~~In August, SPS issued $300 million of 3.4 percent first mortgage bonds due Aug. 15, 2046.~~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 ~~measurement~~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.

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

Specific valuation methods include the following:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted ~~prices.~~net asset value (NAV).

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

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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 2.2 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 ~~energy congestion, which is caused by~~transmission congestion. In addition to overall transmission load, ~~and transmission constraints. Congestion~~congestion is also influenced by the operating schedules of power plants and the consumption of ~~electricity.~~electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

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If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. ~~Given~~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 fair value measurements for FTRs have been assigned a Level 3. Monthly~~model. Non-trading monthly FTR settlements ~~for non-trading FTRs~~ are included in fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs, ~~relative to the electric utility operations of NSP-Minnesota and SPS,~~ the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy.

Non-Derivative Instruments Fair Value Measurements

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 ~~purpose of~~ decommissioning the Monticello and PI nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.

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

Unrealized gains for the nuclear decommissioning fund were ~~$355.3~~$462.3 million and ~~$328.8~~$378.6 million at ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015,~~2016, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were ~~$65.8~~$34.2 million and ~~$100.2~~$46.9 million at ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015,~~2016, respectively.

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The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015:~~2016:


	Sept. 30, 2016												June 30, 2017
			Fair Value												Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total		Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	15,055	$	15,055	$	—	$	—	$	—	$	15,055	$	10,990	$	10,990	$	—	$	—	$	—	$	10,990
Commingled funds:
Non U.S. equities	254,362		—		—		—		245,481		245,481		280,608		191,881		—		—		106,085		297,966
Emerging market debt funds	92,472		—		—		—		101,387		101,387		96,008		—		—		—		103,736		103,736
Commodity funds	99,771		—		—		—		82,139		82,139		106,571		—		—		—		82,897		82,897
Private equity investments	130,848		—		—		—		178,768		178,768		138,889		—		—		—		195,491		195,491
Real estate	121,271		—		—		—		174,552		174,552		131,270		—		—		—		195,515		195,515
Other commingled funds	151,048		—		—		—		159,230		159,230		131,243		—		—		—		141,918		141,918
Debt securities:
Government securities	34,853		—		35,723		—		—		35,723		38,319		—		37,844		—		—		37,844
U.S. corporate bonds	95,828		—		93,981		—		—		93,981		141,510		—		142,330		—		—		142,330
International corporate bonds	19,877		—		19,860		—		—		19,860
Municipal bonds	13,906		—		14,638		—		—		14,638
Asset-backed securities	2,847		—		2,948		—		—		2,948
Mortgage-backed securities	10,118		—		10,582		—		—		10,582
Non U.S. corporate bonds													24,386		—		24,859		—		—		24,859
Equity securities:
U.S. equities	270,137		455,035		—		—		—		455,035		287,425		526,581		—		—		—		526,581
Non U.S. equities	213,291		225,782		—		—		—		225,782		171,695		226,868		—		—		—		226,868
Total	$	1,525,684	$	695,872	$	177,732	$	—	$	941,557	$	1,815,161	$	1,558,914	$	956,320	$	205,033	$	—	$	825,642	$	1,986,995


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes ~~$134.5~~$133.2 million of equity investments in unconsolidated subsidiaries and ~~$98.8~~$111.4 million of rabbi trust assets and miscellaneous investments.


^(b)	~~Based on the requirements~~Due to limited availability of ~~ASU 2015-07,~~published pricing and a lack of immediate redeemability, certain fund investments measured at ~~fair value using a~~ NAV ~~methodology have~~are not ~~been classified in~~required to be categorized within the fair value hierarchy. ~~See Note 2 for further information on the adoption of ASU 2015-07.~~

Table of Contents


	Dec. 31, 2015												Dec. 31, 2016
			Fair Value												Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total		Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	27,484	$	27,484	$	—	$	—	$	—	$	27,484	$	20,379	$	20,379	$	—	$	—	$	—	$	20,379
Commingled funds:
Non U.S. equities	259,114		—		—		—		231,122		231,122		260,877		133,126		—		—		112,233		245,359
Emerging market debt funds	88,987		—		—		—		88,467		88,467		93,597		—		—		—		97,543		97,543
Commodity funds	99,771		—		—		—		77,338		77,338		106,571		—		—		—		92,091		92,091
Private equity investments	105,965		—		—		—		157,528		157,528		132,190		—		—		—		190,462		190,462
Real estate	115,019		—		—		—		165,190		165,190		128,630		—		—		—		187,647		187,647
Other commingled funds	150,877		—		—		—		164,389		164,389		151,048		—		—		—		159,489		159,489
Debt securities:
Government securities	24,444		—		21,356		—		—		21,356		32,764		—		31,965		—		—		31,965
U.S. corporate bonds	73,061		—		65,276		—		—		65,276		104,913		—		105,772		—		—		105,772
International corporate bonds	13,726		—		12,801		—		—		12,801
Non U.S. corporate bonds													21,751		—		21,672		—		—		21,672
Municipal bonds	49,255		—		51,589		—		—		51,589		13,609		—		13,786		—		—		13,786
Asset-backed securities	2,837		—		2,830		—		—		2,830
Mortgage-backed securities	11,444		—		11,621		—		—		11,621		2,785		—		2,816		—		—		2,816
Equity securities:
U.S. equities	273,106		432,495		—		—		—		432,495		270,779		473,400		—		—		—		473,400
Non U.S. equities	200,509		214,664		—		—		—		214,664		189,100		218,381		—		—		—		218,381
Total	$	1,495,599	$	674,643	$	165,473	$	—	$	884,034	$	1,724,150	$	1,528,993	$	845,286	$	176,011	$	—	$	839,465	$	1,860,762


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes ~~$130.0~~$132.8 million of equity investments in unconsolidated subsidiaries and ~~$48.9~~$98.3 million of rabbi trust assets and miscellaneous investments.


^(b)	~~Based on the requirements~~Due to limited availability of ~~ASU 2015-07,~~published pricing and a lack of immediate redeemability, certain fund investments measured at ~~fair value using a~~ NAV ~~methodology have~~are not ~~been classified in~~required to be categorized within the fair value hierarchy. ~~See Note 2 for further information on the adoption of ASU 2015-07.~~

~~Table of Contents~~

For the ~~nine~~three and six months ended ~~Sept.~~June 30, ~~2016~~2017 and ~~2015~~2016 there were no Level 3 nuclear decommissioning fund investments and no transfers of amounts between levels.

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at ~~Sept.~~June 30, ~~2016:~~2017:


	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		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	$	—	$	10,583	$	971	$	24,169	$	35,723	$	—	$	2,770	$	6,497	$	28,577	$	37,844
U.S. corporate bonds	257		28,245		59,451		6,028		93,981		2,824		44,843		78,518		16,145		142,330
International corporate bonds	—		5,043		11,606		3,211		19,860
Municipal bonds	—		210		5,773		8,655		14,638
Asset-backed securities	—		—		2,948		—		2,948
Mortgage-backed securities	—		—		—		10,582		10,582
Non U.S. corporate bonds											—		10,964		10,851		3,044		24,859
Debt securities	$	257	$	44,081	$	80,749	$	52,645	$	177,732	$	2,824	$	58,577	$	95,866	$	47,766	$	205,033

Rabbi Trusts

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


	Sept. 30, 2016										June 30, 2017
			Fair Value										Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total		Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts ^(a)
Cash equivalents	$	47,762	$	47,762	$	—	$	—	$	47,762	$	11,214	$	11,214	$	—	$	—	$	11,214
Mutual funds	1,594		1,867		—		—		1,867		46,171		47,380		—		—		47,380
Total	$	49,356	$	49,629	$	—	$	—	$	49,629	$	57,385	$	58,594	$	—	$	—	$	58,594

Table of Contents



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


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

~~An immaterial amount of mutual funds were held in rabbi trusts at Dec. 31, 2015.~~

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.

~~Table of Contents~~

At ~~Sept.~~June 30, ~~2016,~~2017, accumulated other comprehensive losses related to interest rate derivatives included ~~$3.4~~$3.0 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 ~~energy-related instruments.~~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.~~committee, which is made up of management personnel not directly involved in the activities governed by this policy.

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

At ~~Sept.~~June 30, ~~2016,~~2017, Xcel Energy had various vehicle fuel contracts designated as cash flow hedges extending through December ~~2016.~~2018. Xcel Energy ~~also~~ enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but ~~are~~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 ~~nine~~six months ended ~~Sept.~~June 30, ~~2016~~2017 and ~~2015.~~2016.

At ~~Sept.~~June 30, ~~2016,~~2017, net ~~losses~~gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included immaterial ~~net losses~~amounts 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.

Table of Contents

The following table details the gross notional amounts of commodity forwards, options and FTRs at ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015:~~2016:


(Amounts in Thousands) ^(a)(b)	Sept. 30, 2016	Dec. 31, 2015	June 30, 2017	Dec. 31, 2016
Megawatt hours of electricity	64,040	50,487	101,225	46,773
Million British thermal units of natural gas	116,144	20,874	66,974	121,978
Gallons of vehicle fuel	35	141	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.

~~Table of Contents~~

The following tables detail the impact of derivative activity during the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2016~~2017 and ~~2015,~~2016, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:


	Three Months Ended Sept. 30, 2016																	Three Months Ended June 30, 2017
	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					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
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)							Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities				Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)					Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	1,502	^(a)	$	—		$	—				$	—		$	—			$	1,319		^(a)	$	—			$	—
Vehicle fuel and other commodity	(6		)	—			46		^(b)	—			—					43			—				(5		)	^(b)	—				—
Total	$	(6	)	$	—		$	1,548		$	—		$	—				$	43		$	—			$	1,314			$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	1,779		^(c)		$	—		$	—			$	—			$	—			$	5,785	^(c)
Electric commodity	—			15,497			—			2,491		^(d)	—					—			(1,299		)		—				(2,315		)	^(d)	—
Natural gas commodity	—			(5,737		)	—			—			(6		)	^(e)		—			(1,685		)		—				—				—
Total	$	—		$	9,760		$	—		$	2,491		$	1,773				$	—		$	(2,984	)		$	—			$	(2,315	)		$	5,785

Nine Months Ended Sept. 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 $ —
$ —
$ 4,470
^(a)
$ —
$ —

Vehicle fuel and other commodity 7
—
150
^(b)
—
—

Total $ 7
$ —
$ 4,620
$ —
$ —

Other derivative instruments
Commodity trading $ —
$ —
$ —
$ —
$ 3,269
^(c)
Electric commodity —
14,528
—
30,024
^(d)
—

Natural gas commodity —
(2,376 ) —
11,666
^(e)
(5,005 )
^(e)
Total $ —
$ 12,152
$ —
$ 41,690
$ (1,736 )



	Three Months Ended Sept. 30, 2015																	Six Months Ended June 30, 2017
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Losses Recognized During the Period in Income					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)							Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities				Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)
Derivatives designated as cash flow hedges													Pre-Tax Losses Recognized During the Period in Income
Interest rate	$	—		$	—		$	1,118	^(a)	$	—		$	—				$	—		$	—			$	2,678		^(a)	$	—			$	—
Vehicle fuel and other commodity	(70		)	—			34		^(b)	—			—					43			—				(5		)	^(b)	—				—
Total	$	(70	)	$	—		$	1,152		$	—		$	—				$	43		$	—			$	2,673			$	—			$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	(3,460	)	^(c)		$	—		$	—			$	—			$	—			$	6,786		^(c)
Electric commodity	—			(2,403		)	—			2,860		^(d)	—					—			(505		)		—				(6,313		)	^(d)	—
Natural gas commodity	—			(2,978		)	—			—			(405		)	^(e)		—			(7,846		)		—				1,075			^(e)	(4,070		)	^(e)
Total	$	—		$	(5,381	)	$	—		$	2,860		$	(3,865	)			$	—		$	(8,351	)		$	—			$	(5,238	)		$	2,716

2824

Table of Contents



	Nine Months Ended Sept. 30, 2015																	Three Months Ended June 30, 2016
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax 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)							Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities				Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)				Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges													Pre-Tax Losses Recognized During the Period in Income									��
Interest rate	$	—		$	—		$	3,013	^(a)	$	—		$	—				$	—		$	—			$	1,483	^(a)	$	—		$	—
Vehicle fuel and other commodity	(59		)	—			88		^(b)	—			—					19			—				47		^(b)	—			—
Total	$	(59	)	$	—		$	3,101		$	—		$	—				$	19		$	—			$	1,530		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	(5,896	)	^(c)		$	—		$	—			$	—		$	—		$	481	^(c)
Electric commodity	—			(16,611		)	—			16,020		^(d)	—					—			(705		)		—			16,642		^(d)	—
Natural gas commodity	—			(3,366		)	—			8,685		^(e)	(9,455		)	^(e)		—			6,063				—			—			25		^(e)
Total	$	—		$	(19,977	)	$	—		$	24,705		$	(15,351	)			$	—		$	5,358			$	—		$	16,642		$	506



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

^(e)

~~Amounts for the three and nine months ended Sept. 30, 2016 included no settlement gains or losses on~~Certain derivatives ~~entered~~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 ~~nine~~six months ended ~~Sept.~~June 30, ~~2015~~2017 included ~~$0.4~~no settlement gains or losses and $0.9 million ~~and $0.5 million, respectively,~~ of settlement ~~losses on derivatives entered to mitigate natural gas price risk~~gains, respectively. Amounts for ~~electric generation, recorded to electric fuel~~the three and ~~purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate.~~six months ended June 30, 2016 included an immaterial amount of settlement losses. The remaining derivative settlement gains and losses for the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2016~~2017 and ~~2015~~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 ~~nine~~six months ended ~~Sept.~~June 30, ~~2016~~2017 and ~~2015.~~2016. 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.~~transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of Xcel Energy’s own credit risk when determining the fair value of derivative liabilities, the impact of ~~considering~~ credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.

Xcel Energy Inc. and its subsidiaries employ additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

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 ~~Sept.~~June 30, ~~2016, one~~2017, two of Xcel Energy’s 10 most significant counterparties for these activities, comprising ~~$14.1~~$28.1 million or 612 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, ~~Ratings Services,~~ Moody’s ~~Investor Services~~ or Fitch Ratings. ~~Nine~~Eight of the 10 most significant counterparties, comprising ~~$73.4~~$75.7 million or 3332 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 of these significant counterparties are ~~RTOs,~~ municipal or cooperative electric entities or other utilities.

Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including ~~those recorded to the consolidated balance sheet at fair value, as well as~~ those accounted for as normal purchase-normal sale contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary is unable to maintain its credit ratings. At ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015,~~2016, there were no derivative instruments in a liability position with underlying contract provisions that ~~would have~~ required the posting of collateral or settlement of applicable outstanding contracts if the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment grade.

~~Table of 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 ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015.~~2016.

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 ~~Sept.~~June 30, ~~2016:~~2017:


	Sept. 30, 2016														June 30, 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				Counterparty Netting ^(b)			Level 1			Level 2		Level 3				Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative assets							Fair Value Total
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity															$	—	$	25	$	—	$	25	$	(25	)	$	—
Other derivative instruments:													Total
Commodity trading	$	3,846	$	11,239	$	—	$	15,085	$	(9,440	)		$	5,645	2,974		13,383		2		16,359		(8,958		)	7,401
Electric commodity	—		—		27,775		27,775		(3,180		)		24,595		—		—		68,069		68,069		(4,048		)	64,021
Natural gas commodity	—		6,034		—		6,034		(15		)		6,019		—		1,439		—		1,439		—			1,439
Total current derivative assets	$	3,846	$	17,273	$	27,775	$	48,894	$	(12,635	)		36,259		$	2,974	$	14,847	$	68,071	$	85,892	$	(13,031	)	72,861
PPAs ^(a)													6,601													5,626
Current derivative instruments													$	42,860												$	78,487
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity															$	—	$	14	$	—	$	14	$	—		$	14
Other derivative instruments:
Commodity trading	$	501	$	32,538	$	—	$	33,039	$	(8,306	)		$	24,733	250		30,686		5,215		36,151		(7,307		)	28,844
Natural gas commodity	—		681		—		681		—				681
Total noncurrent derivative assets	$	501	$	33,219	$	—	$	33,720	$	(8,306	)		25,414		$	250	$	30,700	$	5,215	$	36,165	$	(7,307	)	28,858
PPAs ^(a)													25,955													21,552
Noncurrent derivative instruments													$	51,369												$	50,410

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	Sept. 30, 2016														June 30, 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				Counterparty Netting ^(b)			Level 1			Level 2		Level 3				Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative liabilities							Fair Value Total
Derivatives designated as cash flow hedges:													Total
Vehicle fuel and other commodity	$	—	$	41	$	—	$	41	$	—			$	41	$	—	$	—	$	—	$	—	$	(25	)	$	(25	)
Other derivative instruments:
Commodity trading	3,921		8,000		—		11,921		(9,527		)		2,394		3,050		11,443		1		14,494		(9,280		)	5,214
Electric commodity	—		—		3,180		3,180		(3,180		)		—		—		—		4,048		4,048		(4,048		)	—
Natural gas commodity	—		15		—		15		(15		)		—
Total current derivative liabilities	$	3,921	$	8,056	$	3,180	$	15,157	$	(12,722	)		2,435		$	3,050	$	11,443	$	4,049	$	18,542	$	(13,353	)	5,189
PPAs ^(a)													22,766													22,830
Current derivative instruments													$	25,201												$	28,019
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	538	$	24,114	$	—	$	24,652	$	(11,005	)		$	13,647	$	98	$	22,861	$	—	$	22,959	$	(10,522	)	$	12,437
Total noncurrent derivative liabilities	$	538	$	24,114	$	—	$	24,652	$	(11,005	)		13,647		$	98	$	22,861	$	—	$	22,959	$	(10,522	)	12,437
PPAs ^(a)													141,003													123,818
Noncurrent derivative instruments													$	154,650												$	136,255

^(a)

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

^(b)

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 ~~Sept.~~June 30, ~~2016.~~2017. At ~~Sept.~~June 30, ~~2016,~~2017, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of ~~$2.8~~$3.5 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 at Dec. 31, ~~2015:~~2016:


		Dec. 31, 2015															Dec. 31, 2016
		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				Counterparty Netting ^(b)			Level 1				Level 2		Level 3				Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative assets								Fair Value Total
Other derivative instruments:														Total
Commodity trading		$	225	$	10,620	$	1,250	$	12,095	$	(5,865	)		$	6,230		$	13,179	$	14,105	$	—	$	27,284	$	(20,637	)	$	6,647
Electric commodity		—		—		21,421		21,421		(4,088		)		17,333			—		—		19,251		19,251		(1,976		)	17,275
Natural gas commodity		—		496		—		496		(303		)		193			—		8,839		—		8,839		—			8,839
Total current derivative assets	Total current derivative assets	$	225	$	11,116	$	22,671	$	34,012	$	(10,256	)		23,756		Total current derivative assets	$	13,179	$	22,944	$	19,251	$	55,374	$	(22,613	)	32,761
PPAs ^(a)														10,086														5,463
Current derivative instruments														$	33,842													$	38,224
Noncurrent derivative assets
Other derivative instruments:
Commodity trading		$	—	$	27,416	$	—	$	27,416	$	(6,555	)		$	20,861		$	100	$	31,029	$	—	$	31,129	$	(7,323	)	$	23,806
Natural gas commodity																	—		1,652		—		1,652		—			1,652
Total noncurrent derivative assets	Total noncurrent derivative assets	$	—	$	27,416	$	—	$	27,416	$	(6,555	)		20,861		Total noncurrent derivative assets	$	100	$	32,681	$	—	$	32,781	$	(7,323	)	25,458
PPAs ^(a)														30,222														24,731
Noncurrent derivative instruments														$	51,083													$	50,189

Table of Contents


	Dec. 31, 2015														Dec. 31, 2016
	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				Counterparty Netting ^(b)			Level 1			Level 2		Level 3				Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative liabilities							Fair Value Total
Derivatives designated as cash flow hedges:													Total
Vehicle fuel and other commodity	$	—	$	205	$	—	$	205	$	—			$	205
Other derivative instruments:
Commodity trading	152		7,866		555		8,573		(6,904		)		1,669		$	13,787	$	11,320	$	22	$	25,129	$	(20,974	)	$	4,155
Electric commodity	—		—		4,088		4,088		(4,088		)		—		—		—		1,976		1,976		(1,976		)	—
Natural gas commodity	—		5,407		—		5,407		(303		)		5,104
Total current derivative liabilities	$	152	$	13,478	$	4,643	$	18,273	$	(11,295	)		6,978		$	13,787	$	11,320	$	1,998	$	27,105	$	(22,950	)	4,155
PPAs ^(a)													22,861													22,804
Current derivative instruments													$	29,839												$	26,959
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	—	$	19,898	$	—	$	19,898	$	(9,780	)		$	10,118	$	89	$	23,424	$	—	$	23,513	$	(10,727	)	$	12,786
Total noncurrent derivative liabilities	$	—	$	19,898	$	—	$	19,898	$	(9,780	)		10,118		$	89	$	23,424	$	—	$	23,513	$	(10,727	)	12,786
PPAs ^(a)													158,193													135,360
Noncurrent derivative instruments													$	168,311												$	148,146

^(a)

^(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, ~~2015.~~2016. At Dec. 31, ~~2015,~~2016, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of ~~$4.3~~$3.7 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 ~~nine~~six months ended ~~Sept.~~June 30, ~~2016~~2017 and ~~2015:~~2016:



	Three Months Ended Sept. 30						Three Months Ended June 30
(Thousands of Dollars)	2016			2015			2017			2016
Balance at July 1	$	24,517		$	46,826
Balance at April 1							$	5,836		$	6,854
Purchases	274			486			76,281			29,826
Settlements	(33,982		)	(20,216		)	(22,272		)	(14,111		)
Net transactions recorded during the period:
Gains recognized in earnings ^(a)	9			121
Gains recognized as regulatory assets and liabilities	33,777			3,966
Balance at Sept. 30	$	24,595		$	31,183
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

	Nine Months Ended Sept. 30						Six Months Ended June 30
(Thousands of Dollars)	2016			2015			2017			2016
Balance at Jan. 1	$	18,028		$	56,155		$	17,253		$	18,028
Purchases	33,296			63,724			80,073			31,670
Settlements	(60,707		)	(57,462		)	(42,074		)	(26,161		)
Net transactions recorded during the period:
(Losses) gains recognized in earnings ^(a)	(33		)	1,401
Gains (losses) recognized as regulatory assets and liabilities	34,011			(32,635		)
Balance at Sept. 30	$	24,595		$	31,183
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


^(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 ~~nine~~six months ended ~~Sept.~~June 30, ~~2016~~2017 and ~~2015.~~2016.

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Fair Value of Long-Term Debt

As of ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015,~~2016, other financial instruments for which the carrying amount did not equal fair value were as follows:


	Sept. 30, 2016				Dec. 31, 2015				June 30, 2017				Dec. 31, 2016
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion ^(a)	$	14,112,150	$	16,127,060	$	13,055,901	$	14,094,744	$	14,597,178	$	15,879,594	$	14,450,247	$	15,513,209


^(a)	~~Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2,~~ ~~Accounting Pronouncements~~ ~~for more information on the adoption of ASU 2015-03.~~

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 ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015,~~2016, 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 Sept. 30					Nine Months Ended Sept. 30						Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2016			2015		2016			2015			2017			2016			2017			2016
Interest income	$	1,385		$	312	$	6,439		$	4,939		$	2,107		$	984		$	5,907		$	5,054
Other nonoperating income	341			625		2,517			2,387			1,523			1,496			5,168			2,176
Insurance policy (expense) income	(1,148		)	689		(2,568		)	(1,578		)
Insurance policy expense												(1,022		)	(920		)	(2,021		)	(1,420		)
Other income, net	$	578		$	1,626	$	6,388		$	5,748		$	2,608		$	1,560		$	9,054		$	5,810


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 ~~$134.5~~$133.2 million and ~~$130.0~~$132.8 million as of ~~Sept.~~June 30, ~~2016~~2017 and Dec. 31, ~~2015,~~2016, 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 expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total
Three Months Ended Sept. 30, 2016
Operating revenues from external customers $ 2,799,964
$ 221,956
$ 18,227
$ —
$ 3,040,147
Intersegment revenues 282
292
—
(574 ) —
Total revenues $ 2,800,246
$ 222,248
$ 18,227
$ (574 ) $ 3,040,147
Net income (loss) $ 479,399
$ (5,297 ) $ (16,307 ) $ —
$ 457,795

(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total
Three Months Ended Sept. 30, 2015
Operating revenues from external customers $ 2,667,480
$ 216,019
$ 17,813
$ —
$ 2,901,312
Intersegment revenues 392
293
—
(685 ) —
Total revenues $ 2,667,872
$ 216,312
$ 17,813
$ (685 ) $ 2,901,312
Net income (loss) $ 437,978
$ (4,176 ) $ (7,339 ) $ —
$ 426,463

(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total
Nine Months Ended Sept. 30, 2016
Operating revenues from external customers $ 7,209,225
$ 1,046,544
$ 56,500
$ —
$ 8,312,269
Intersegment revenues 1,038
820
—
(1,858 ) —
Total revenues $ 7,210,263
$ 1,047,364
$ 56,500
$ (1,858 ) $ 8,312,269
Net income (loss) $ 863,076
$ 84,974
$ (52,148 ) $ —
$ 895,902

3229

Table of Contents


(Thousands of Dollars)	Regulated Electric			Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total		Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2015
Three Months Ended June 30, 2017
Operating revenues from external customers	$	7,105,803		$	1,216,146	$	56,716		$	—		$	8,378,665	$	2,338,017	$	289,839	$	17,072		$	—		$	2,644,928
Intersegment revenues	1,142			1,141		—			(2,283		)	—		433		285		—			(718		)	—
Total revenues	$	7,106,945		$	1,217,287	$	56,716		$	(2,283	)	$	8,378,665	$	2,338,450	$	290,124	$	17,072		$	(718	)	$	2,644,928
Net income (loss)	$	733,954	^(a)	$	72,617	$	(31,111	)	$	—		$	775,460	$	227,562	$	13,166	$	(13,472	)	$	—		$	227,256

^(a)



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



(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

~~Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5.~~


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 dilutive impact to EPS include commitments to issue common stock related to time based equity compensation ~~awards and time based employer matching contributions to certain 401(k) plan participants.~~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.

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



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

Three Months Ended Sept. 30, 2016 Three Months Ended Sept. 30, 2015
(Amounts in thousands, except per share data) Income Shares
Per Share
Amount
Income Shares
Per Share
Amount
Net income $ 457,795
—
—
$ 426,463
—
—
Basic EPS:
Earnings available to common shareholders 457,795
508,941
$ 0.90
426,463
508,031
$ 0.84
Effect of dilutive securities:
Time based equity awards —
625
—
—
396
—
Diluted EPS:
Earnings available to common shareholders $ 457,795
509,566
$ 0.90
$ 426,463
508,427
$ 0.84

~~Table of Contents~~


	Nine Months Ended Sept. 30, 2016					Nine Months Ended Sept. 30, 2015					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		Income		Shares	Per Share Amount		Income		Shares	Per Share Amount
Net income	$	895,902	—	—		$	775,460	—	—		$	466,533	—	—		$	438,107	—	—
Basic EPS:
Earnings available to common shareholders	895,902		508,840	$	1.76	775,460		507,585	$	1.53	466,533		508,411	$	0.92	438,107		508,789	$	0.86
Effect of dilutive securities:
Time based equity awards	—		556	—		—		391	—		—		544	—		—		522	—
Diluted EPS:
Earnings available to common shareholders	$	895,902	509,396	$	1.76	$	775,460	507,976	$	1.53	$	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 Sept. 30												Three Months Ended June 30
	2016			2015			2016			2015			2017			2016			2017			2016
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits						Pension Benefits						Postretirement Health Care Benefits
Service cost	$	22,940		$	24,828		$	432		$	529		$	23,547		$	22,945		$	465		$	431
Interest cost	40,027			37,131			6,527			6,324			36,702			40,028			5,984			6,526
Expected return on plan assets	(52,575		)	(53,473		)	(6,249		)	(6,650		)	(52,318		)	(52,575		)	(6,155		)	(6,248		)
Amortization of prior service credit	(478		)	(451		)	(2,672		)	(2,672		)	(442		)	(477		)	(2,672		)	(2,671		)
Amortization of net loss	24,384			31,288			1,011			1,351			26,671			24,385			1,672			1,009
Net periodic benefit cost (credit)	34,298			39,323			(951		)	(1,118		)	34,160			34,306			(706		)	(953		)
Costs not recognized due to the effects of regulation	(3,976		)	(7,016		)	—			—			(3,899		)	(4,159		)	—			—
Net benefit cost (credit) recognized for financial reporting	$	30,322		$	32,307		$	(951	)	$	(1,118	)	$	30,261		$	30,147		$	(706	)	$	(953	)

Table of Contents


	Nine Months Ended Sept. 30												Six Months Ended June 30
	2016			2015			2016			2015			2017			2016			2017			2016
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits						Pension Benefits						Postretirement Health Care Benefits
Service cost	$	68,805		$	74,484		$	1,295		$	1,587		$	47,094		$	45,865		$	930		$	863
Interest cost	120,078			111,393			19,580			18,972			73,404			80,051			11,968			13,053
Expected return on plan assets	(157,725		)	(160,418		)	(18,746		)	(19,950		)	(104,635		)	(105,150		)	(12,311		)	(12,497		)
Amortization of prior service credit	(1,439		)	(1,353		)	(8,015		)	(8,015		)	(884		)	(961		)	(5,343		)	(5,343		)
Amortization of net loss	73,154			93,864			3,031			4,053			53,341			48,770			3,344			2,020
Net periodic benefit cost (credit)	102,873			117,970			(2,855		)	(3,353		)	68,320			68,575			(1,412		)	(1,904		)
Costs not recognized due to the effects of regulation	(12,587		)	(22,035		)	—			—			(7,914		)	(8,611		)	—			—
Net benefit cost (credit) recognized for financial reporting	$	90,286		$	95,935		$	(2,855	)	$	(3,353	)	$	60,406		$	59,964		$	(1,412	)	$	(1,904	)

In January ~~2016,~~2017, contributions of ~~$125.0~~$150.0 million were made across four of Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during ~~2016.~~2017.

~~Table of Contents~~


13.	Other Comprehensive Income

Changes in accumulated other comprehensive (loss) income, net of tax, for the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2016~~2017 and ~~2015~~2016 were as follows:


	Three Months Ended Sept. 30, 2016											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			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 July 1	$	(52,980	)	$	110	$	(53,925	)	$	(106,795	)
Other comprehensive loss before reclassifications	(4		)	—		—			(4		)
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	960			—		878			1,838			803			—		956			1,759
Net current period other comprehensive income	956			—		878			1,834			829			1		956			1,786
Accumulated other comprehensive (loss) income at Sept. 30	$	(52,024	)	$	110	$	(53,047	)	$	(104,961	)
Accumulated other comprehensive (loss) income at June 30												$	(49,497	)	$	111	$	(57,409	)	$	(106,795	)

Three Months Ended Sept. 30, 2015
(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 July 1 $ (56,436 ) $ 112
$ (48,862 ) $ (105,186 )
Other comprehensive loss before reclassifications (42 ) (1 ) —
(43 )
Losses reclassified from net accumulated other comprehensive loss 706
—
884
1,590
Net current period other comprehensive income (loss) 664
(1 ) 884
1,547
Accumulated other comprehensive (loss) income at Sept. 30 $ (55,772 ) $ 111
$ (47,978 ) $ (103,639 )



	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	)

Nine Months Ended Sept. 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 Jan. 1 $ (54,862 ) $ 110
$ (55,001 ) $ (109,753 )
Other comprehensive income (loss) before reclassifications 4
—
(653 ) (649 )
Losses reclassified from net accumulated other comprehensive loss 2,834
—
2,607
5,441
Net current period other comprehensive income 2,838
—
1,954
4,792
Accumulated other comprehensive (loss) income at Sept. 30 $ (52,024 ) $ 110
$ (53,047 ) $ (104,961 )


	Nine Months Ended Sept. 30, 2015											Six 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			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	$	(57,628	)	$	110	$	(50,621	)	$	(108,139	)	$	(51,151	)	$	110	$	(59,313	)	$	(110,354	)
Other comprehensive (loss) income before reclassifications	(35		)	1		—			(34		)
Other comprehensive income before reclassifications												26			1		—			27
Losses reclassified from net accumulated other comprehensive loss	1,891			—		2,643			4,534			1,628			—		1,904			3,532
Net current period other comprehensive income	1,856			1		2,643			4,500			1,654			1		1,904			3,559
Accumulated other comprehensive (loss) income at Sept. 30	$	(55,772	)	$	111	$	(47,978	)	$	(103,639	)
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 ~~nine~~six months ended ~~Sept.~~June 30, ~~2016~~2017 and ~~2015~~2016 were as follows:



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

Amounts Reclassified from Accumulated
Other Comprehensive Loss

(Thousands of Dollars) Three Months Ended Sept. 30, 2016 Three Months Ended Sept. 30, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives $ 1,502
^(a)
$ 1,118
^(a)
Vehicle fuel derivatives 46
^(b)
34
^(b)
Total, pre-tax 1,548
1,152

Tax benefit (588 ) (446 )
Total, net of tax 960
706

Defined benefit pension and postretirement (gains) losses:
Amortization of net loss 1,478
^(c)
1,532
^(c)
Prior service credit (64 )
^(c)
(89 )
^(c)
Total, pre-tax 1,414
1,443

Tax benefit (536 ) (559 )
Total, net of tax 878
884

Total amounts reclassified, net of tax $ 1,838
$ 1,590


	Amounts Reclassified from Accumulated Other Comprehensive Loss								Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2016				Nine Months Ended Sept. 30, 2015				Six Months Ended June 30, 2017				Six Months Ended June 30, 2016
(Gains) losses on cash flow hedges:
Losses (gains) on cash flow hedges:
Interest rate derivatives	$	4,470		^(a)	$	3,013		^(a)	$	2,678		^(a)	$	2,968		^(a)
Vehicle fuel derivatives	150			^(b)	88			^(b)	(5		)	^(b)	104			^(b)
Total, pre-tax	4,620				3,101				2,673				3,072
Tax benefit	(1,786		)		(1,210		)		(1,045		)		(1,198		)
Total, net of tax	2,834				1,891				1,628				1,874
Defined benefit pension and postretirement (gains) losses:
Defined benefit pension and postretirement losses:
Amortization of net loss	4,434			^(c)	4,600			^(c)	3,244			^(c)	2,956			^(c)
Prior service credit	(192		)	^(c)	(268		)	^(c)	(117		)	^(c)	(128		)	^(c)
Total, pre-tax	4,242				4,332				3,127				2,828
Tax benefit	(1,635		)		(1,689		)		(1,223		)		(1,099		)
Total, net of tax	2,607				2,643				1,904				1,729
Total amounts reclassified, net of tax	$	5,441			$	4,534			$	3,532			$	3,603


^(a)	Included in interest 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.

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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.

~~Table of Contents~~

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 ~~2016 and~~ 2017 earnings per share guidance and assumptions, are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we 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, ~~2015 and Quarterly Reports on Form 10-Q for the quarters ended March 31,~~ 2016, and ~~June 30, 2016),~~subsequent securities 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; 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 ofor cost of capital; and employee work force factors.

Financial Review

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 diluted EPS for Xcel Energy and by subsidiary is a financial measure not recognized under GAAP. 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 this non-GAAP financial measure to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe this measurement is useful 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.

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Results of Operations

The following table summarizes diluted EPS for Xcel Energy:


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended June 30						Six Months Ended June 30
Diluted Earnings (Loss) Per Share	2016			2015			2016			2015			2017			2016			2017			2016
PSCo	$	0.34		$	0.34		$	0.74		$	0.75		$	0.20		$	0.17		$	0.42		$	0.40
NSP-Minnesota	0.41			0.35			0.74			0.65			0.17			0.15			0.36			0.34
SPS	0.13			0.12			0.24			0.21			0.07			0.06			0.12			0.11
NSP-Wisconsin	0.05			0.05			0.11			0.13			0.03			0.02			0.07			0.06
Equity earnings of unconsolidated subsidiaries	0.01			0.01			0.04			0.03			0.01			0.01			0.02			0.03
Regulated utility(a)	0.94			0.87			1.87			1.77			0.48			0.42			0.99			0.93
Xcel Energy Inc. and other	(0.04		)	(0.03		)	(0.11		)	(0.08		)	(0.03		)	(0.04		)	(0.07		)	(0.07		)
Ongoing diluted EPS	0.90			0.84			1.76			1.69
Loss on Monticello LCM/EPU project	—			—			—			(0.16		)
GAAP diluted EPS	$	0.90		$	0.84		$	1.76		$	1.53
GAAP diluted EPS ^(a)													$	0.45		$	0.39		$	0.92		$	0.86

~~Table of Contents~~


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

Earnings Adjusted for Certain Items (Ongoing Earnings)

Ongoing earnings reflect adjustments to 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.

For the nine months ended Sept. 30, 2015, GAAP earnings included a $0.16 per share charge related to the Monticello nuclear facility LCM/EPU project, which in total cost $748 million. In March 2015, the MPUC approved full recovery, including a return, on $415 million of the project costs, inclusive of AFUDC, but only allowed recovery of the remaining $333 million of costs with no return on this portion of the investment for years 2015 and beyond. As a result of this decision, Xcel Energy recorded a pre-tax charge of approximately $129 million in the first quarter of 2015. See Note 5 to the consolidated financial statements for further discussion.

Summary of ~~Ongoing~~ Earnings

Xcel Energy — Xcel Energy’s ~~ongoing~~ earnings increased $0.06 per share for the ~~third~~second quarter of ~~2016~~2017 and ~~$0.07 per share year-to-date, which excludes~~year-to-date. Earnings for the ~~2015 adjustment for a charge related~~second quarter of 2017 increased due to ~~the NSP-Minnesota Monticello LCM/EPU project. Electric~~higher electric and natural gas margins ~~rose in the third quarter primarily driven by higher retail electric and natural gas rates and non-fuel riders~~ to recover ~~our capital~~infrastructure investments, along with ~~higher sales growth. These positive factors and~~ a lower effective tax rate ~~were~~and lower operating and maintenance (O&M) expenses, partially offset by higher ~~depreciation, operating and maintenance expenses and interest charges.~~depreciation.

PSCo— ~~PSCo’s ongoing earnings were flat~~— Earnings increased $0.03 per share for the ~~third~~second quarter of ~~2016~~2017 and ~~decreased~~$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. ~~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 ~~natural gas~~electric margins primarily due to rate increases, ~~and higher AFUDC were offset by higher depreciation, O&M expenses and interest charges.~~

~~NSP-Minnesota~~— NSP-Minnesota’s ongoing earnings increased $0.06 for the third quarter of 2016 and $0.09 per share year-to-date. Year-to-date, higher electric revenues driven by an interim electric rate increase in Minnesota (subject to refund) and non-fuel riderswhich were partially offset by ~~higher depreciation, O&M expenses, interest charges and property taxes.~~

~~SPS~~— SPS’ ongoing earnings increased $0.01 for the third quarter of 2016 and $0.03 per share year-to-date. Year-to-date, higher electric margins and lower O&M expenses were partially offset by an increase inadditional depreciation.

~~NSP-Wisconsin~~ — NSP-Wisconsin’s ongoing earnings were flat for the third quarter of 2016 and decreased $0.02 per share year-to-date. Year-to-date, the positive impact of higher electric revenues, primarily driven by an electric rate increase, was offset by higher O&M expenses and depreciation.

~~Xcel Energy Inc. and other~~ — Xcel Energy Inc. and other includes financing costs at the holding company and other items. Ongoing earnings decreased by $0.01 for the third quarter of 2016 and $0.03 per share year-to-date, primarily related to higher long-term debt levels.

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Changes in Diluted EPS

The following table summarizes significant components contributing to the changes in ~~2016~~2017 EPS compared with the same period in ~~2015:~~2016:

Diluted Earnings (Loss) Per Share Three Months Ended Sept. 30 Nine Months Ended Sept. 30
2015 GAAP diluted EPS $ 0.84
$ 1.53
Loss on Monticello LCM/EPU project —
0.16
2015 ongoing diluted EPS 0.84
1.69

Components of change — 2016 vs. 2015
Higher electric margins^(a)
0.14
0.27
Lower ETR 0.02
0.04
Higher natural gas margins ^(b)
0.01
0.03
Higher depreciation and amortization (0.06 ) (0.17 )
Higher interest charges (0.02 ) (0.05 )
Higher O&M expenses (0.03 ) (0.03 )
Other, net —
(0.02 )
2016 GAAP and ongoing diluted EPS $ 0.90
$ 1.76



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


^(a)	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.

^(a)~~Reflects $0.006 and $0.015 attributable to weather for the three and nine months ended Sept. 30, 2016, respectively.~~

^(b)~~Reflects $0.001 and $(0.007) attributable to weather for the three and nine months ended Sept. 30, 2016, respectively.~~

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 per degree of temperature. Accordingly, deviations in weather from normal levels can affect Xcel Energy’s financial performance.

Degree-day or Temperature-Humidity Index (THI) data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. Heating degree-days (HDD) is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. 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.

The percentage increase (decrease) in normal and actual HDD, CDD and THI is provided in the following table:


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended June 30						Six Months Ended June 30
	2016 vs. Normal		2015 vs. Normal		2016 vs. 2015		2016 vs. Normal		2015 vs. Normal		2016 vs. 2015		2017 vs. Normal		2016 vs. Normal		2017 vs. 2016		2017 vs. Normal		2016 vs. Normal		2017 vs. 2016
HDD	(52.6	)%	(57.9	)%	11.1	%	(12.7	)%	(4.2	)%	(8.4	)%	(9.8	)%	(3.7	)%	(7.2	)%	(8.5	)%	(11.5	)%	2.3	%
CDD	11.0		15.1		(3.1	)	8.3		5.4		3.3		5.4		1.7		3.7		7.4		1.7		5.5
THI	6.5		4.3		3.2		8.6		(1.6	)	11.2		(3.9	)	15.8		(16.1	)	(6.9	)	15.4		(21.4	)

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


	Three Months Ended Sept. 30									Nine Months Ended Sept. 30										Three Months Ended June 30									Six Months Ended June 30
	2016 vs. Normal				2015 vs. Normal			2016 vs. 2015		2016 vs. Normal				2015 vs. Normal			2016 vs. 2015			2017 vs. Normal			2016 vs. Normal			2017 vs. 2016			2017 vs. Normal			2016 vs. Normal			2017 vs. 2016
Retail electric	$	0.016		^(a)	$	0.010		$	0.006	$	0.011		^(a)	$	(0.004	)	$	0.015		$	0.005		$	0.013		$	(0.008	)	$	(0.021	)	$	(0.004	)	$	(0.017	)
Firm natural gas	(0.001		)		(0.002		)	0.001		(0.014		)		(0.007		)	(0.007		)	(0.002		)	—			(0.002		)	(0.020		)	(0.013		)	(0.007		)
Total	$	0.015			$	0.008		$	0.007	$	(0.003	)		$	(0.011	)	$	0.008
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	)


^(a)	~~Excludes $0.008 and $0.009 favorable weather impact due to electric sales decoupling at NSP-Minnesota for the three and nine months ended Sept. 30, 2016, respectively.~~

Sales Growth (Decline) — The following tables summarize Xcel Energy and its subsidiaries’ sales growth (decline) for actual and weather-normalized sales in ~~2016~~2017 compared to the same period in ~~2015:~~2016:


	Three Months Ended Sept. 30										Three Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential ^(a)	5.6	%	4.7	%	1.5	%	2.8	%	4.4	%	(1.5	)%	(1.4	)%	6.4	%	0.7	%	(0.3	)%
Electric commercial and industrial	0.1		0.8		3.6		—		1.2		2.6		(0.9	)	2.5		3.4		1.3
Total retail electric sales	2.0		2.0		3.2		0.7		2.2		1.4		(1.1	)	3.1		2.7		0.9
Firm natural gas sales	3.5		(5.0	)	N/A		(12.8	)	(0.2	)	(8.5	)	3.6		N/A		4.2		(4.7	)


	Three Months Ended Sept. 30										Three Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized
Electric residential ^(a)	4.8	%	2.0	%	1.0	%	1.0	%	2.8	%	(0.3	)%	0.8	%	0.8	%	2.3	%	0.5	%
Electric commercial and industrial	0.5		0.2		3.4		(0.2	)	1.0		3.0		(0.4	)	2.3		3.7		1.5
Total retail electric sales	2.1		0.8		3.1		—		1.6		2.0		(0.1	)	1.9		3.4		1.3
Firm natural gas sales	(1.6	)	(4.9	)	N/A		(12.9	)	(3.2	)	(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	)


	Nine Months Ended Sept. 30										Six Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Weather-normalized
Electric residential ^(a)	4.2	%	1.7	%	(1.7	)%	(0.5	)%	1.9	%	(0.6	)%	0.1	%	(1.5	)%	0.9	%	(0.3	)%
Electric commercial and industrial	(0.7	)	(0.3	)	1.6		(0.3	)	—		0.7		(0.5	)	1.4		1.6		0.5
Total retail electric sales	0.9		0.3		1.0		(0.5	)	0.6		0.3		(0.4	)	0.7		1.3		0.2
Firm natural gas sales	3.2		(9.0	)	N/A		(12.5	)	(1.8	)	(1.0	)	4.2		N/A		3.3		0.9

Nine Months Ended Sept. 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-normalized
Electric residential ^(a)
3.4 % 0.6 % (1.2 )% (0.3 )% 1.3 %
Electric commercial and industrial (0.7 ) (0.7 ) 1.2
(0.4 ) (0.3 )
Total retail electric sales 0.7
(0.3 ) 0.8
(0.5 ) 0.2
Firm natural gas sales 0.9
(0.6 ) N/A
(4.7 ) —

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	Nine Months Ended Sept. 30 (Excluding Leap Day) ^(b)										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
Electric residential ^(a)	3.0	%	0.2	%	(1.6	)%	(0.7	)%	0.9	%	—	%	0.7	%	(0.9	)%	1.5	%	0.3	%
Electric commercial and industrial	(1.1	)	(1.1	)	0.8		(0.7	)	(0.6	)	1.2		—		1.9		2.1		1.0
Total retail electric sales	0.3		(0.7	)	0.4		(0.8	)	(0.2	)	0.9		0.2		1.2		1.9		0.8
Firm natural gas sales	0.1		(1.4	)	N/A		(5.4	)	(0.7	)	(0.2	)	5.1		N/A		4.2		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 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 ~~30-40~~50-60 basis points for retail electric and ~~70-80~~80-90 basis points for firm natural gas for the ~~nine~~six months ~~ended Sept. 30, 2016.~~ended.

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

Day

PSCo’s flat residential ~~growth reflects~~sales reflect an increased number of customers and ~~higher~~lower use per customer. The commercial and industrial (C&I) ~~decline~~growth was mainly due to ~~lower sales to certain~~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 mining, oil and gas industries. ~~The decline was partially offset by an increase in the number of small C&I customers.~~

NSP-Minnesota’s residential sales growth reflects customer additions, partially offset by lower use per customer. Flat C&I sales ~~declined primarily as a result of~~resulted from lower ~~use~~sales to small customers, offset by ~~small and~~customer growth. Increased sales to large customers in ~~the~~ manufacturing ~~industry.~~and energy industries offset smaller declines in services and air transportation.

SPS’ residential ~~sales decline was primarily the result of~~fell largely due to lower use per customer. ~~The increase in~~ C&I sales ~~was~~growth reflects higher use per customer driven by the oil and natural gas ~~production~~industry in the ~~Southeastern New Mexico,~~ Permian ~~Basin area as well as greater use by agricultural customers.~~Basin.

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

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 ~~large and small C&I~~ customers, ~~as well as greater use per customer in the large C&I class for the oil and gas industries.~~

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

~~Across natural gas service territories, lower natural gas sales reflect~~partially offset by a decline in customer ~~use, partially offset by a slight increase in the number of customers.~~use.

Electric Revenues and Margin

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


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended June 30						Six Months Ended June 30
(Millions of Dollars)	2016			2015			2016			2015			2017			2016			2017			2016
Electric revenues	$	2,800		$	2,667		$	7,209		$	7,106		$	2,338		$	2,224		$	4,637		$	4,409
Electric fuel and purchased power	(1,037		)	(1,015		)	(2,755		)	(2,870		)	(919		)	(856		)	(1,844		)	(1,718		)
Electric margin	$	1,763		$	1,652		$	4,454		$	4,236		$	1,419		$	1,368		$	2,793		$	2,691

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

Electric Revenues


(Millions of Dollars)	Three Months Ended Sept. 30 2016 vs. 2015			Nine Months Ended Sept. 30 2016 vs. 2015			Three Months Ended June 30 2017 vs. 2016			Six Months Ended June 30 2017 vs. 2016
Retail rate increases ^(a)	$	59		$	132
Transmission revenue	16			53
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	11			19			(6		)	(13		)
Non-fuel riders	8			16
Retail sales growth, excluding weather impact	18			15
Conservation incentive	7			7
Fuel and purchased power cost recovery	7			(141		)
Weather decoupling-Minnesota	(6		)	(7		)
PSCo earnings test refund	5			(1		)
Other, net	8			10			1			6
Total increase in electric revenues	$	133		$	103		$	114		$	228


^(a)	~~Increase is primarily related to interim rates in Minnesota (subject to and net of estimated provision for refund) and final rates in Wisconsin.~~

Electric Margin


(Millions of Dollars)	Three Months Ended Sept. 30 2016 vs. 2015			Nine Months Ended Sept. 30 2016 vs. 2015			Three Months Ended June 30 2017 vs. 2016			Six Months Ended June 30 2017 vs. 2016
Retail rate increases ^(a)	$	59		$	132
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	11			19			(6		)	(13		)
Non-fuel riders	8			16
Retail sales growth, excluding weather impact	18			15
Transmission revenue, net of costs	1			13
Conservation incentive	7			7
Weather decoupling-Minnesota	(6		)	(7		)
PSCo earnings test refund	5			(1		)
Other, net	8			24			—			3
Total increase in electric margin	$	111		$	218		$	51		$	102


^(a)	~~Increase is primarily due to interim rates in Minnesota (subject to and net of estimated provision for refund) and final rates in Wisconsin.~~

Natural Gas Revenues and Margin

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


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended June 30						Six Months Ended June 30
(Millions of Dollars)	2016			2015			2016			2015			2017			2016			2017			2016
Natural gas revenues	$	222		$	216		$	1,047		$	1,216		$	290		$	259		$	916		$	825
Cost of natural gas sold and transported	(68		)	(66		)	(470		)	(665		)	(114		)	(90		)	(479		)	(402		)
Natural gas margin	$	154		$	150		$	577		$	551		$	176		$	169		$	437		$	423

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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 Sept. 30 2016 vs. 2015			Nine Months Ended Sept. 30 2016 vs. 2015			Three Months Ended June 30 2017 vs. 2016			Six Months Ended June 30 2017 vs. 2016
Purchased natural gas adjustment clause recovery	$	(3	)	$	(200	)	$	23		$	76
Retail rate increases^(a)	8			32
Infrastructure and integrity riders							5			12
Higher conservation and DSM revenues (offset by higher expenses)							1			4
Estimated impact of weather							(1		)	(5		)
Other, net	1			(1		)	3			4
Total increase (decrease) in natural gas revenues	$	6		$	(169	)
Total increase in natural gas revenues							$	31		$	91


^(a)	~~Increase is primarily related to final rates in Colorado.~~

Natural Gas Margin


(Millions of Dollars)	Three Months Ended Sept. 30 2016 vs. 2015			Nine Months Ended Sept. 30 2016 vs. 2015			Three Months Ended June 30 2017 vs. 2016			Six Months Ended June 30 2017 vs. 2016
Retail rate increases^(a)	$	8		$	32
Infrastructure and integrity riders							$	5		$	12
Higher conservation and DSM revenues (offset by higher expenses)							1			4
Estimated impact of weather	—			(5		)	(1		)	(5		)
Non-fuel riders	(3		)	(5		)
Other, net	(1		)	4			2			3
Total increase in natural gas margin	$	4		$	26		$	7		$	14


^(a)	~~Increase is primarily related to final rates in Colorado.~~

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses ~~increased $24.0~~decreased $18.8 million, or ~~4.2~~3.2 percent, for the ~~third~~second quarter of ~~2016~~2017 and ~~$18.3~~decreased $9.8 million, or ~~1.0~~0.8 percent, ~~for~~year-to-date. The year-to-date decrease is primarily due to the ~~nine months ended Sept. 30,~~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 ~~compared~~expenses associated with the ~~same periods~~Texas 2016 electric rate case (approximately $8 million) recognized in ~~2015. The year-to-date increase was mainly due to additional maintenance activities and storm related costs, which were partially~~2017 in connection with the settlement, offset by ~~a reduction in the timing and scope of plant outages and discovery work.~~revenue recovery.

Conservation and ~~Demand Side Management (DSM) Program~~DSM Expenses — Conservation and ~~DSM program~~demand side management (DSM) expenses increased ~~$6.6~~$8.9 million, or ~~11.5~~16.0 percent, for the ~~third~~second quarter of ~~2016~~2017 and ~~$12.0~~increased $19.0 million, or ~~7.3~~16.8 percent, ~~for the nine months ended Sept. 30, 2016 compared with the same periods in 2015.~~year-to-date. Increases were ~~primarily attributable~~due to ~~more~~higher recovery rates and additional customer participation in ~~DSM~~electric conservation programs, ~~which has led to additional customer rebates~~mostly in Minnesota. Conservation and ~~increased program implementation costs. Higher conservation and~~ DSM ~~program~~ expenses are generally ~~offset by higher revenues due~~recovered in our major jurisdictions concurrently through riders and base rates. Timing of recovery may not correspond to ~~recovery mechanisms.~~the period in which costs were incurred.

Depreciation and Amortization — Depreciation and amortization increased ~~$48.4~~$43.2 million, or ~~17.3~~13.4 percent, for the ~~third~~second quarter of ~~2016~~2017 and ~~$143.2~~increased $88.4 million, or ~~17.3~~13.8 percent, ~~for the nine months ended Sept. 30, 2016 compared with the same periods in 2015. Increases were~~year-to-date. The increase was primarily ~~attributable~~due to capital investments ~~including Pleasant Valley~~ and ~~Border Wind Farms, reduction~~prior year amortization of the excess depreciation reserve in ~~Minnesota and the full amortization of the DOE settlement in 2015.~~Minnesota.

~~Taxes (Other Than Income Taxes)~~Allowance for Funds Used During Construction (AFUDC), Equity and Debt — ~~Taxes (other than income taxes) decreased $5.9~~AFUDC increased $2.6 million ~~or 4.8 percent,~~ for the ~~third~~second quarter of ~~2016~~2017 and increased ~~$11.5~~$4.8 million ~~or 3.0 percent, for the nine months ended Sept. 30, 2016 compared with the same periods in 2015.~~year-to-date. The ~~year-to-date~~ increase was primarily due to higher ~~property taxes in Minnesota, excluding~~average capital investments, particularly the ~~impact of the proposed settlement agreement in the Minnesota 2016 multi-year electric rate case.~~Rush Creek wind project.

Interest Charges — Interest charges increased ~~$13.3~~$1.2 million, or ~~8.7~~0.7 percent, for the ~~third~~second quarter of ~~2016~~2017 and ~~$43.6~~increased $10.7 million, or ~~9.9~~3.4 percent, ~~for the nine months ended Sept. 30, 2016 compared with the same periods in 2015. Increases were~~year-to-date. The increase was related to higher ~~long-term~~ debt levels to fund capital investments, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense decreased $2.0 million for the second quarter of 2017 compared with the same period in 2016. The decrease was primarily due 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 second quarter of 2017. The ETR was 31.1 percent for the second quarter of 2017 compared with 34.7 percent for the same period in 2016. The lower ETR in 2017 was primarily due to the adjustments referenced above.

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~~Income Taxes~~ —

Income tax expense decreased ~~$0.6~~$14.0 million for the ~~third quarter~~first six months of ~~2016~~2017 compared with the same period in ~~2015.~~2016. The decrease in income tax expense was primarily due to ~~increased~~an increase in wind ~~production~~PTCs in 2017, an increase in permanent plant-related adjustments (e.g., AFUDC-equity) in 2017 and a tax ~~and research and experimentation credits~~expense for a state tax credit valuation allowance in 2016, partially offset by higher pretax earnings in ~~2016.~~the six months ended June 30, 2017. The ETR was ~~34.2~~32.0 percent for the ~~third quarter~~first six months of ~~2016~~2017, compared ~~with 35.9~~to 34.7 percent for the ~~same period in 2015.~~first six months of 2016. The lower ETR in ~~2016 is primarily due to the adjustments referenced above.~~

~~Income tax expense increased $39.0 million for the first nine months of 2016 compared with the same period in 2015. The increase in income tax expense~~2017 was primarily due to higher pretax earnings, partially offset by increased wind production tax and research and experimentation credits. The ETR was 34.5 percent for the first nine months of 2016 compared with 35.8 percent for the same period in 2015. The lower ETR in 2016 is 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, ~~2015~~2016 and Public Utility Regulation included in Item 2 of Xcel Energy Inc.’s

Quarterly ~~Reports~~Report on Form 10-Q for the quarterly ~~periods~~period ended March 31, ~~2016 and June 30, 2016,~~2017, appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

~~NSP-Minnesota~~Xcel Energy Inc.

~~NSP Resource Plans~~Wind Development — ~~In January 2015,~~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 ~~filed its 2016-2030 Integrated Resource Plan (the Plan) with the MPUC.~~and 1,230 MW at SPS. Previously, Xcel Energy received regulatory approval to build a 600 MW wind farm at PSCo.

~~Subsequently, NSP-Minnesota proposed revisions~~In July 2017, the MPUC approved NSP-Minnesota’s proposal to the Plan, which addressed stakeholder recommendations as well as the Clean Power Plan issued by the EPA. The revised plan was based on four primary elements: (1) accelerate the transition from coal energy to renewables, (2) preserve regional system reliability, (3) pursue energy efficiency gains and grid modernization, and (4) ensure customer benefits. The revised plan includes substantial opportunities for NSP-Minnesotaadd 1,550 MW of new wind generation, including ownership of ~~renewable~~1,150 MW of wind generation ~~and~~by NSP-Minnesota. The MPUC approved an aggregate capital cap for the 750 MW of self-build projects, allowing NSP-Minnesota to include in rate base any savings versus a capital cost estimate for the projects. NSP-Minnesota would ~~result~~not recover capital costs in ~~63 percent of NSP System energy being carbon-free by 2030 and a 60 percent reduction in carbon emissions from 2005 levels by 2030.~~

~~Specific terms~~excess of the ~~proposal include:~~cap.

The ~~addition of 1,800 MW of~~PUCT and NMPRC are expected to rule on SPS’ wind ~~and 1,400 MW of solar between 2016-2030, including approximately 650 MW of solar from NSP-Minnesota’s community solar gardens program by 2020;~~

~~The retirement of Sherco Unit 2 in 2023 and Sherco Unit 1 in 2026;~~

~~Partial replacement of Sherco coal generation with a 786 MW natural gas combined cycle unit at the Sherco site to coincide with the Unit 1 retirement;~~

~~The addition of a 230 MW natural gas combustion turbine in North Dakota~~projects by the end of ~~2025;~~the first quarter of 2018.

~~Operation of the Monticello and PI nuclear plants through their current license periods~~Key dates in the ~~early 2030’s~~ PUCT procedural schedule are as follows:

Intervenor testimony — Oct. 2, 2017;

Staff testimony — Oct. 9, 2017;

Rebuttal testimony — Oct. 23, 2017; and

Hearing — Nov. 6 - Nov. 17, 2017.

Key dates in the NMPRC procedural schedule are as follows:

Staff and a commitment to provide additional information regarding forecasted cost increases at PI through end of licensed life if the MPUC wishes to further explore alternatives to operating PI through its current license periods.intervenor testimony — Oct. 24, 2017;

Rebuttal testimony — Nov. 9, 2017; and

Hearing — Nov. 28 - Dec. 1, 2017.

In ~~October 2016, the MPUC verbally approved NSP-Minnesota’s plan, with modifications as follows:~~

~~The acquisition of at least 1,000~~total, Xcel Energy has proposed adding 3,380 MW of wind capacity by ~~2019, with additional acquisitions dependent on considerations such as price, bidder qualifications,~~the end of 2020. Xcel Energy has filed to own and place in rate ~~impact, transmission availability and location;~~

~~The acquisition of 650~~base 2,750 MW of ~~solar before 2021~~these wind projects, while 630 MW would be through ~~the community solar gardens program or other acquisitions - and pursuit of additional, cost-effective solar resources if it is in the best interests of its customers;~~

~~Determination~~PPAs. These wind projects would qualify for 100 percent of the ~~proper~~production tax credit and are intended to provide billions of dollars of savings to our customers and substantial environmental benefits. Projected savings/benefits assume fuel costs and generation mix ~~of purchased power~~consistent with those included in various commission approved resource plans and ~~Company-owned renewable resources shall be made during the resource acquisition process;~~generation need filings.

Retirement of Sherco Unit 2 in 2023 and Sherco Unit 1 in 2026, and a finding that more likely than not, there will be a need for approximately 750 MW of capacity coinciding with the retirement of Sherco Unit 1 in 2026;

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~~Authorization~~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 — In June and July 2017, NSP-Minnesota ~~to file a petition for a certificate of need to select the resource that best meets the system resource and local reliability needs associated~~filed requests with the ~~retirement of Sherco Unit 1 in 2026;~~

~~Acquisition of no less than 400 MW of additional demand response by 2023; and~~

~~Submission of NSP-Minnesota’s next Resource Plan by February 2019.~~MPUC and/or the NDPSC for several initiatives including changes to four PPAs to reduce future costs for customers. These actions include the following:

The ~~MPUC’s order on NSP-Minnesota’s Resource Plan is expected~~termination of a PPA with Benson Power LLC (Benson) for its 55 MW biomass facility in ~~late 2016.~~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.

~~Request~~The termination of a PPA with Laurentian Energy Authority I, LLC (Laurentian) for ~~Proposal (RFP)~~ ~~— In September 2016, NSP-Minnesota issued a RFP for 1,500~~its 35 MW of ~~wind generation to be~~biomass facilities in ~~service by 2020.~~Hibbing and Virginia, Minn. The ~~RFP requests both PPAs and Build-Own-Transfer proposals. NSP-Minnesota intends to compare self-build options to the RFP bids to ensure that all resource additions are cost-competitive.~~

In October 2016, NSP-Minnesota submitted a petition for approval to the MPUC of a 750 MW self-build wind farm portfolio. RFP bids were received in October 2016 and will be evaluated in conjunction with the self-build proposal.

~~An overview~~termination of the ~~anticipated RFP schedule is as follows:~~Laurentian PPA would result in $108.5 million of contract cancellation payments over six years.

~~Project proposal selection~~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 ~~negotiation will occur from November 2016 to March 2017;~~

~~An NSP-Minnesota recommendation for proposed wind additions to the MPUC in the first quarter~~termination of ~~2017; and~~

~~MPUC approval is expected by July 2017.~~

~~Minnesota Solar~~ —Minnesota legislation requires 1.5 percent of a public utility’s total electric retail sales to retail customers be generated using solar energy by 2020. Of the 1.5 percent, 10 percent must come from systems sized 20 kilowatts or less. NSP-Minnesota anticipates it will meet its compliance requirements through large and small scale solar additions.another 12 MW waste-to-energy PPA.

NSP-Minnesota ~~also offers customer solar programs:~~has requested recovery of all costs associated with these changes through the Fuel Clause Adjustment, including a solar production incentive program for rooftop solar, called Solar*Rewards®, and a community solar garden program that provides bill credits to participating subscribers, called Solar*Rewards® Community®. Additionally, the DOC offers the “Made in Minnesota” program, providing incentives for the installation of small solar systems that were manufactured in-state, which generates renewable energy credits for utilities including NSP-Minnesota.

~~In August 2015, the MPUC issued an order regarding the Solar*Rewards Community program, limiting the size of solar installations eligible to participate~~return on NSP-Minnesota’s total investment in the ~~program. The order was appealed~~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 Minnesota Court of Appeals, which affirmed the MPUC’s decision. The decision was subsequently appealed to the Minnesota Supreme Court, which denied the appeal in September 2016, terminating the case.next 10 years.

Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the PI plant. See Note 14 of Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2015~~2016 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 Annual Report on Form 10-K for the year ended Dec. 31, ~~2015~~2016 and Nuclear Power Operations included in Item 2 of Xcel Energy Inc.’s Quarterly ~~Reports~~

Report on Form 10-Q for the quarterly ~~periods~~period ended March 31, ~~2016 and June 30, 2016,~~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 ~~nine months~~year ended ~~Sept. 30,~~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.~~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 ~~$3.5~~$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 of over-recovery up to two percent of authorized annual fuel costs, or approximately $3.7 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. Accordingly, NSP-Wisconsin recorded a deferral of approximately ~~$6.6~~$3.0 million through ~~Sept.~~June 30, ~~2016.~~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 ~~2017~~2018, NSP-Wisconsin will file a reconciliation of ~~2016~~2017 fuel costs with the PSCW. The amount of any potential refund is subject to review and approval by the PSCW, which is not expected until ~~mid-2017.~~mid-2018.

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PSCo

~~Colorado 2016 Electric Resource Plan~~ — In May 2016, PSCo filed its 2016 Electric Resource Plan which identified approximately 600 MW of additional resources need by the summer of 2023. The CPUC is expected to consider the resource plan in two phases. In the first phase, the CPUC will examine the resource need to address peak demand periods, establish the resource acquisition period and determine modeling parameters used in resource selection for the second phase. The second phase would include solicitation of new resources. PSCo’s base plan, filed in Phase I, addressed various resources including 410 MW of combined cycle generation, 700 MW of combustion turbine generation and approximately 600 MW of customer sited solar generation. Additional scenarios to the plan include adding 600 MW of the Rush Creek Wind Project or 400 MW of wind or utility solar generation.

~~The key dates in the procedural schedule for the first phase of the Electric Resource Plan are as follows:~~

~~Answer testimony — Dec. 9, 2016;~~

~~Rebuttal testimony — Jan. 17, 2017;~~

~~Hearings — Feb. 1-8, 2017; and~~

~~Statements of position — Feb. 17, 2017.~~

~~The second phase of the Electric Resource Plan is anticipated to begin shortly after the conclusion of the first phase.~~

Rush Creek Wind Ownership Proposal — In ~~May~~ 2016, the CPUC granted PSCo ~~filed an application~~a CPCN to build, own and operate a 600 MW wind generation facility in Colorado at Rush ~~Creek for~~Creek. The CPCN includes a ~~cost of approximately $1 billion, including transmission investment.~~

In September 2016, the CPUC approved a settlement between PSCo, the CPUC Staff, the Colorado Office of Consumer Counsel, the Colorado Energy Office and various other parties. This will allow PSCo to commence the project on a timely basis and capture the full production tax credit benefit for customers.

~~Key terms of the settlement are listed below:~~

~~The Rush Creek project satisfies the reasonable cost standard and is in the public interest;~~

~~The project should be placed in service by Oct. 31, 2018;~~

~~The useful life of the project should be set at 25 years;~~

A hard cost-cap ~~on the~~of $1.096 billion ~~investment (which includes the capital investment~~(including transmission costs) and ~~allowance for funds used during construction);~~

Aa 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, with 82.5 percent retained by customers and 17.5 percent retained by PSCo on a net present value basis over the life of the project;~~

Amounts retained by PSCo under the capital cost sharing mechanism as well as overall facility revenue requirements may each be reduced for lower than projected long term generating output (i.e., higher degradation); and

~~The Pawnee-Daniels transmission line (estimated project cost of $178 million) should be accelerated and operations are expected to begin by October 2019.~~cost-cap.

~~PSCo Global Settlement Agreement~~ — In August 2016, PSCo and various intervenors, including small and large customers, state representatives, environmental advocates and solar and energy groups, entered into a global settlement agreement regarding three pending filings withAll major contracts required to complete the ~~CPUC,~~project have been executed including the ~~Phase II electric rate case (which is related to~~Vestas turbine supply and balance of plant agreements. Vestas PTC components for safe harboring the ~~rate design portion~~facility have been fabricated and are currently being stored at Vestas facilities in Colorado. Construction of ~~the 2015 Electric Rate Case), the Renewable*Connect proposal (formally known as Solar*Connect)~~roads, collection systems, and ~~the 2017 Renewable Energy Plan. Key terms of the agreement include that participating customers~~foundations began in the proposed Renewable*Connect program would pay ordinary tariff electric rates in addition to a voluntary tariff solar charge, and receive bill credits related to avoided cost savings for a new 50 MW solar resource. It was also agreed that PSCo’s 2017 Renewable Energy Plan would include 2017 to 2019 acquisition of a total of 225 MW of renewable energy from sources including rooftop solar, solar gardens and recycled energy.

A CPUC decision is expected by December 2016, which would allow PSCo to issue a RFP for the new Renewable*Connect solar facility and implement the 2017 Renewable Energy Plan and the rate design changes of the Phase II electric rate case beginning JanuaryApril 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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~~Joint Dispatch Agreement (JDA)~~2016 Electric Resource Plan (ERP) — In ~~February~~May 2016, ~~the FERC approved a JDA between~~ PSCo Black Hills Colorado Electric Utility Company, LP and Platte River Power Authority. Through the JDA, energy is dispatched to economically serve the combined electric customer loads of the three systems. In circumstances where PSCo is the lowest cost producer, it will sellfiled its ~~excess~~2016 ERP which included its estimated need for additional generation ~~to other JDA counterparties. PSCo proposed with the CPUC that margins on these sales be shared among PSCo~~resources and its ~~customers,~~proposal to acquire those resources through a competitive Request for Proposal (RFP) process. The CPUC issued its decision on Phase I in late April 2017, approving the Phase I modeling assumptions to be used in Phase II and directed PSCo to file an updated capacity need prior to issuing any RFPs. PSCo plans to update the range of ~~which 10 percent would~~resource need to be ~~retained by PSCo. A decision by~~considered within the competitive RFP process and issue the RFP in August 2017. The CPUC is ~~anticipated~~expected to rule on the RFP results in the ~~fourth~~second quarter of 2016. The JDA parties estimate the combined net benefits of the agreement would be approximately $4.5 million, annually. The agreement results in a reduction in total energy costs for the parties, of which approximately $1.4 million would be allocated to PSCo’s customers. As part of the agreement, PSCo will earn a management fee to administer the JDA. We expect operations under the JDA to begin in the fourth quarter of 2016.2018.

Advanced Grid Intelligence and Security —In ~~August 2016, PSCo filed a request with~~July 2017, the CPUC ~~to approve a certificate of public convenience and necessity~~approved PSCo’s CPCN for implementation of its advanced grid initiative. The project incorporates installing advanced meters, implementing ~~a combination of~~ hardware and software applications to allow the distribution system to operate at a lower voltage (integrated volt-var optimization) and installing ~~necessary~~ communications ~~infrastructure to implement this hardware.~~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.

In June 2017, the CPUC approved a settlement, which delayed the advanced meter deployment from 2017-2021 to 2019-2024. The ~~estimated~~total capital ~~investment for~~cost of the project is ~~approximately $500 million. PSCo anticipates a CPUC decision by the third quarter of 2017. If approval is received, the project is expected~~currently estimated to be ~~completed by 2021.~~approximately $537 million for 2017-2024. As a result of the settlement, approximately $120 million of capital investment was deferred to 2022-2024.

Decoupling Filing — In July 2016, PSCo filed a request with the CPUC to approve a partial decoupling mechanism, ~~for a five year period, effective on Jan. 1, 2017. The proposed decoupling adjustment~~which would ~~allow PSCo to~~ adjust annual revenues based on changes in weather normalized average use per customer for the residential and small ~~C&I~~commercial classes. The proposed mechanism is intended to improve PSCo’s ability to collect base rate revenues in the event that average use per customer declines as a result of DSM, distributed generation and other energy saving programs. The proposed decoupling mechanism is symmetric and may result in potential refunds to customers if there were an increase in average use per customer. PSCo did not request that revenue be adjusted as a result of weather related sales fluctuations.

In ~~August 2016,~~July 2017, the CPUC issued a ~~majority~~decision which approved the following key decisions regarding decoupling:

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

Applicable to the residential class and small commercial class;

Based on total class revenues (subject to establishing the base period in the next electric rate case);

Based on actual sales; and

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

PSCo plans to seek reconsideration of the ~~parties to the PSCo Global Settlement Agreement agreed to limit any future opposition to PSCo’s decoupling proposal to the specifics of design and implementation.~~

~~The key dates in the procedural schedule are as follows:~~

~~Direct testimony — Dec. 14, 2016;~~

~~Answer testimony — Jan. 16, 2017;~~

~~Rebuttal and cross answer testimony — Feb. 10, 2017; and~~

~~Hearings — Feb. 21-24, 2017.~~

~~A decision is anticipated in the first quarter of 2017.~~order.

Boulder, Colo. Municipalization — In ~~November~~ 2011, Boulder voters passed a ballot measure ~~was passed which authorized~~authorizing the formation ~~and operation~~ of a municipal ~~utility and the issuance of enterprise revenue bonds, subject to certain restrictions, including the level of initial rates and debt service coverage.~~utility. In ~~May~~ 2014, the ~~City of~~ Boulder ~~(Boulder)~~ City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility as premature because costs and system separation plans were not ~~final, but~~final. The Boulder District Court dismissed the case ~~was dismissed.~~for lack of subject matter jurisdiction. PSCo appealed this ~~decision and in~~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 ~~while vacating~~formation. Boulder subsequently filed a Petition for Writ of Certiorari with the ~~lower court’s decision.~~Colorado Supreme Court. The Supreme Court has not yet ruled whether it will exercise its discretion and review the petition.

In ~~2013,~~January 2015, the Boulder District Court affirmed a prior CPUC ~~ruled~~decision that Boulder ~~may not be the retail service provider to any PSCo~~cannot serve customers ~~located~~ outside ~~Boulder~~its city ~~limits unless Boulder can establish that PSCo is unwilling or unable to serve those customers.~~limits. The ~~CPUC~~District Court also ruled ~~that it~~the CPUC has jurisdiction over the transfer of any facilities to Boulder ~~that currently serve any customers located outside Boulder city limits~~ and ~~will determine separation matters. The CPUC has declared that Boulder must receive CPUC transfer approval prior~~how the systems are separated to ~~any eminent domain actions. Boulder appealed this ruling to the Boulder District Court.~~preserve reliability, safety and effectiveness. In ~~January~~February 2015, the Boulder District Court ~~affirmed the CPUC decision. The Boulder District Court~~ also dismissed athe condemnation action ~~that~~ Boulder had filed. The CPUC must ~~complete~~approve the separation plan ~~proceeding~~ before Boulder ~~may refile a~~files its condemnation proceeding.

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In July 2015, Boulder filed an application with the CPUC requesting approval of its proposed separation plan. ~~In August 2015,~~ PSCo filed a motion to dismiss Boulder’s ~~separation proposal, arguing Boulder’s request was not permissible under Colorado law. In December 2015, the~~application. The CPUC granted the motion to dismiss the application in part, holding that Boulder had no right to acquire PSCo facilities used exclusively to serve customers located outside Boulder city limits. Other portionsdismissed a portion of Boulder’s application, ~~were not dismissed,~~ but ~~were stayed until~~allowed Boulder ~~supplemented~~to supplement its application. Boulder filed its ~~amended~~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.

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Mountain West Transmission Group (MWTG) — PSCo initiated discussions with six other transmission owners from the Rocky Mountain region to evaluate the merits of creating and operating pursuant to a joint transmission tariff that may increase wholesale market efficiency and improve regional transmission planning. In 2016, the MWTG established a non-binding memorandum of understanding to guide their process and issued a request for information to four established RTOs. In January 2017, the MWTG initiated preliminary discussions with the SPP to begin evaluation of the costs and benefits of MWTG participation in the ~~application, Boulder estimates it~~SPP RTO. The CPUC has held informational meetings on certain issues including financial implications and reliability. If PSCo were to move forward with RTO participation, CPUC and FERC approval would ~~incur approximately $53 million of costs~~be required. If approved, operations within the RTO would not be expected to ~~separate from~~begin until 2019, at the earliest. PSCo ~~system.~~will evaluate its options later in 2017 and beyond.

SPS

TUCO Substation to Yoakum County Substation to Hobbs Plant Substation 345 ~~Kilovolt (KV)~~KV Transmission Line — In ~~June 2015, SPS filed a certificate~~March 2016, the PUCT approved SPS’ Certificate of ~~convenience~~Convenience and ~~necessity~~Necessity (CCN) ~~with the PUCT~~ for the 33-mile Yoakum County to Texas/New Mexico State line portion of this 345 KV line project. ~~The PUCT approved this CCN in March 2016.~~ 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 ~~2019.~~2020. A ~~20-mile~~36-mile CCN for the Texas/New Mexico state line to Hobbs Plant segment ~~is planned to be~~was filed in ~~the fourth quarter of 2016 or early~~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, the PUCT Staff requested comments on Lubbock Power & Light’s (LP&L’s) proposal to transition a portion of its load (approximately 430 MW on a peak basis) to the ERCOT in June 2019. 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 based on 2015 revenue requirements.~~revenue. The remaining portion of LP&L’s load (approximately 170 MW) would continue to be served by SPS. Should LP&L join ERCOT, costs to SPS’ remaining customers would increase as SPS’ transmission costs would be spread across a smaller base of customers.

The PUCT has indicated there will be a two-step process regarding LP&L’s possible transfer to ERCOT. The first step will be 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. ~~As part of the first process, the~~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 application with the PUCT for a public interest determination in August 2017. SPS intends to participate in the PUCT’s processes to protect its customers’ interests.

In May 2016, SPS submitted a filing to the FERC seeking approval to impose an Interconnection Switching Fee (exit fee) associated with LP&L’s proposal. In September 2016, FERC dismissed SPS’ petition without prejudice to refile, finding the petition premature since LP&L has not made aNo final decision ~~to move to ERCOT and the terms~~regarding LP&L’s departure or its potential timing is expected until completion of the ~~transition, if any, have not been determined.~~PUCT proceedings.

Summary of Recent Federal Regulatory Developments

~~The Pipeline and Hazardous Materials Safety Administration~~

~~Pipeline Safety Act~~ — The Pipeline Safety, Regulatory Certainty, and Job Creation Act (Pipeline Safety Act) requires additional verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. In April 2016, the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) released proposed rules that address this verification requirement along with a number of other significant changes to gas transmission regulations. These changes include requirements around use of automatic or remote-controlled shut-off valves; testing of certain previously untested transmission lines; and expanding integrity management requirements. The Pipeline Safety Act also includes a maximum penalty for violating pipeline safety rules of $2 million per day for related violations.

Xcel Energy continues to analyze the proposed rule changes as they relate to costs, current operations and financial results. PHMSA has indicated that they intend for the rules to go into effect in late 2017 or early 2018.

Xcel Energy has been taking actions that were intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective. PSCo and NSP-Minnesota can generally recover costs to comply with the transmission and distribution integrity management programs through the pipeline system integrity adjustment and GUIC riders, respectively.

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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, ~~2015~~2016 and Quarterly ~~Reports~~Report on Form 10-Q for the quarterly ~~periods~~period ended March 31, ~~2016 and June 30, 2016.~~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 ~~Order, New~~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 on contested matters pending before the FERC. President Trump has submitted nominations to fill three of the vacant seats and has indicated his intent to submit one additional nomination. The three submitted nominations are pending confirmation by the full Senate.

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FERC ROE Policy — ~~The~~In June 2014, the FERC ~~has~~ adopted a ~~new~~ two-step ROE methodology for electric ~~utilities.~~utilities in an order issued in a complaint proceeding involving New England Transmission Owners (NETOs). The issue of how to apply the ~~new~~ FERC ROE methodology ~~is being~~has been contested in various complaint ~~proceedings. There are~~proceedings, including two ROE complaints ~~against~~involving the MISO TOs, which ~~include~~includes NSP-Minnesota and NSP-Wisconsin. In ~~September 2016,~~April 2017, the D.C. Circuit vacated and remanded the June 2014 ROE order. The D.C. Circuit found that the FERC ~~issued an order in~~had not properly determined that the ~~first MISO~~ ROE ~~complaint which upheld~~authorized for NETOs prior to June 2014 was unjust and unreasonable. The D.C. Circuit also found that the ~~initial~~FERC failed to justify the new ROE methodology. The FERC has yet to act on the D.C. Circuit’s decision made by the ALJ in December 2015. The second complaint is pending FERC action after issuance of an initial decision by the ALJ in June 2016. FERC is not expected to issue an order in the second litigated MISO ROE complaint proceeding until 2017.and cannot act without a quorum. 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.

~~Formula Rate Treatment of Accumulated Deferred Income Taxes (ADIT)~~Public Utility Regulatory Policies Act (PURPA) Enforcement Complaint against CPUC —In ~~2015, NSP-Minnesota, NSP-Wisconsin, SPS~~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 ~~changes~~a motion to ~~their transmission formula rates~~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 ~~changes~~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 ~~its production formula rate,~~be unlawful. PSCo has intervened in that proceeding and the CPUC has filed a motion to ~~comply with IRS guidance regarding how ADIT must~~dismiss. In June 2017, the United States Magistrate Judge (Magistrate) issued a recommendation to the District Court that sPower’s complaint be ~~reflected in formula rates using future test years and~~dismissed because sPower failed to establish that it faced a ~~true-up.~~substantial risk of harm. The ~~filings were intended to ensure that NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are in compliance with IRS rules and may continue to use accelerated tax depreciation.~~Magistrate’s recommendation is pending before the District Court.

Solar Gardens Investment

In ~~December 2015, the FERC partially accepted the proposed~~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 NSP-Wisconsin transmission formula rate changes, but rejected changes regarding the treatment of ADIT in the formula rate true-up. In September 2016, FERC issued an order clarifying that NSP-Minnesota and NSP-Wisconsin may incorporate ADIT true-up provisions in their formula rate. However, submission of a new tariff change filing is required to implement the change. NSP-Minnesota and NSP-Wisconsin expect to file a change to their transmission formula rate in the fourth quarter of 2016 and will request a Jan. 1, 2016 effective date.2018.

Golden Spread protested the proposed changes to the SPS transmission formula rate. In April 2016, FERC accepted the SPS and PSCo transmission formula rate and PSCo production formula rate changes, subject to compliance filings. SPS and PSCo submitted the compliance filings in May 2016. In August 2016, FERC approved the PSCo and SPS compliance filings.

~~SPP and MISO Complaints Regarding RTO Joint Operating Agreement (JOA)~~ —SPP and MISO were involved in a long-running dispute regarding the interpretation of their JOA, which is intended to coordinate RTO operations along the MISO/SPP system boundary. SPP and MISO disagreed over MISO’s authority to transmit power between the traditional MISO region in the Midwest and the Entergy system. Several cases were filed with the FERC by MISO and SPP between 2011 and 2014.

In January 2016, the FERC approved a settlement between SPP, MISO and other parties that resolves various disputed matters and provides a defined settlement compensation plan by MISO to SPP. MISO will pay SPP $16 million for the two-year retroactive period (February 2014 to January 2016) and $16 million annually prospectively starting Feb. 1, 2016, subject to a true-up. In January 2016, SPP filed a proposal regarding distribution of the MISO revenues to SPP members, including SPS. In March 2016, the FERC issued an order rejecting one component of the SPP filing, accepting the remainder of the SPP tariff proposal subject to refund. In August 2016, MISO and other parties filed a settlement regarding the April 2014 MISO tariff change filing to recover SPP JOA charges in MISO rates. The settlement is pending FERC approval. NSP-Minnesota and NSP-Wisconsin expect to be able to recover any resulting MISO charges in retail rates. The JOA revenue allocated to SPS under the filed SPP proposal was not expected to be material.

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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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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 ~~energy-related instruments.~~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.

At ~~Sept.~~June 30, ~~2016,~~2017, the fair values by source for net commodity trading contract assets were as follows:


	Futures / Forwards											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		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	$	2,719	$	6,582	$	1,500	$	303	$	11,104	1	$	1,928	$	6,534		$	1,550	$	—	$	10,012
PSCo	1	461		2		—		—		463		1	396		(11		)	—		—		385
PSCo												2	1		—			—		—		1
		$	3,180	$	6,584	$	1,500	$	303	$	11,567		$	2,325	$	6,523		$	1,550	$	—	$	10,398


	Options													Options
(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			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	$	(16	)	$	—	$	—	$	—	$	(16	)	2	$	(512	)	$	2,129	$	3,042	$	—	$	4,659

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:

Nine Months Ended Sept. 30
(Thousands of Dollars) 2016 2015
Fair value of commodity trading net contract assets outstanding at Jan. 1 $ 11,040
$ 21,811
Contracts realized or settled during the period (2,628 ) (4,400 )
Commodity trading contract additions and changes during period 3,139
(3,169 )
Fair value of commodity trading net contract assets outstanding at Sept. 30 $ 11,551
$ 14,242

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

At ~~Sept.~~June 30, 2016, a 10 percent increase in market prices for commodity trading contracts would decrease pretax income from continuing operations by approximately $0.3 million, whereas a 10 percent decrease would increase pretax income from continuing operations by approximately $0.3 million. At Sept. 30, 2015,2017, a 10 percent increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately ~~$0.5~~$0.3 million, whereas a 10 percent decrease would decrease pretax income from continuing operations by approximately ~~$0.5~~$0.8 million. At June 30, 2016, a 10 percent increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $0.1 million, whereas a 10 percent decrease would decrease pretax income from continuing operations by approximately $0.1 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, ~~including transactions that are not recorded at fair value,~~ 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 Sept. 30		VaR Limit		Average		High		Low		Three Months Ended June 30		VaR Limit		Average		High		Low
2017											$	0.26	$	3.00	$	0.38	$	0.66	$	0.04
2016	$	0.10	$	3.00	$	0.18	$	0.38	$	0.05	0.22		3.00		0.22		0.38		0.06
2015	0.17		3.00		0.23		0.63		0.10

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Nuclear Fuel Supply — NSP-Minnesota is scheduled to take delivery of approximately ~~87 percent of its 2016 and approximately~~ 13 percent of its 2017 and approximately 54 percent of its 2018 enriched nuclear material requirements from sources that could be impacted by events in Ukraine and sanctions against 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 3531 percent of its average enriched nuclear material requirements from sources that could be impacted by events in Ukraine and extended sanctions against Russia. 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.

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 has indicated its intention 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.

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 ~~Sept.~~June 30, ~~2016~~2017 and ~~2015,~~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 ~~$4.2~~$9.4 million and ~~$0.8~~$5.9 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 ~~Sept.~~June 30, ~~2016,~~2017, 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 ana 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 ~~Sept.~~June 30, ~~2016,~~2017, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of ~~$11.7~~$18.1 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of ~~$15.9~~$2.1 million. At ~~Sept.~~June 30, ~~2015,~~2016, a 10 percent increase in commodity prices would have resulted in a decrease in credit exposure of ~~$4.8~~$9.2 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of ~~$11.7~~$16.4 million.

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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 ~~Sept.~~June 30, ~~2016.~~2017. 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 ~~Sept.~~June 30, ~~2016.~~2017.

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 ~~1.3~~3.5 percent and ~~8.0~~9.8 percent of total assets and liabilities, respectively, measured at fair value at ~~Sept.~~June 30, ~~2016.~~2017.

Determining the fair value of FTRs requires numerous management forecasts that vary in observability, including various forward commodity prices, retail and wholesale demand, generation and resulting transmission system congestion. Given the limited observability of management’s forecasts for several of these inputs, these instruments have been assigned a Level 3. Level 3 commodity derivatives assets and liabilities included ~~$27.8~~$68.1 million and ~~$3.2~~$4.0 million of estimated fair values, respectively, for FTRs held at ~~Sept.~~June 30, ~~2016.~~2017.

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 no$5.2 million in Level 3 commodity ~~forwards~~derivative assets and no liabilities for options held at ~~Sept.~~June 30, ~~2016.~~2017. There were immaterial Level 3 forwards held at June 30, 2017.

Liquidity and Capital Resources

Cash Flows


	Nine Months Ended Sept. 30				Six Months Ended June 30
(Millions of Dollars)	2016		2015		2017		2016
Cash provided by operating activities	$	2,413	$	2,490	$	1,292	$	1,425

Net cash provided by operating activities decreased ~~$77~~$133 million for the ~~nine~~six months ended ~~Sept.~~June 30, ~~2016~~2017 compared with the ~~nine~~six months ended ~~Sept.~~June 30, ~~2015.~~2016. The decrease was primarily due to lower tax refunds received and the timing of vendor payments, customer receipts, refunds, and recovery onof certain electric and natural gas riders, ~~and incentive programs,~~ partially offset by ~~timing of vendor payments and~~ higher net income, excluding amounts related to non-cash operating activities (e.g., depreciation and deferred tax ~~expenses and a charge related to the Monticello LCM/EPU project in 2015)~~expenses).


	Nine Months Ended Sept. 30						Six Months Ended June 30
(Millions of Dollars)	2016			2015			2017			2016
Cash used in investing activities	$	(2,206	)	$	(2,139	)	$	(1,474	)	$	(1,443	)

Net cash used in investing activities increased ~~$67~~$31 million for the ~~nine~~six months ended ~~Sept.~~June 30, ~~2016~~2017 compared with the ~~nine~~six months ended ~~Sept.~~June 30, ~~2015.~~2016. The increase was primarily attributable to higher capital expenditures related to the ~~establishment of~~Rush Creek wind generation facility, partially offset by lower rabbi ~~trusts~~trust investments in ~~2016 and the impact of higher insurance proceeds received in 2015.~~

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2017.


	Nine Months Ended Sept. 30					Six Months Ended June 30
(Millions of Dollars)	2016		2015			2017		2016
Cash provided by (used in) financing activities	$	62	$	(26	)
Cash provided by financing activities						$	159	$	10

Net cash provided by financing activities ~~was $62~~increased $149 million for the ~~nine~~six months ended ~~Sept.~~June 30, ~~2016~~2017 compared with ~~net cash used in financing activities of $26 million for~~ the ~~nine~~six months ended ~~Sept.~~June 30, ~~2015, or a change of $88 million.~~2017. The ~~difference~~increase was primarily ~~due~~attributable to lower repayments of ~~short-term~~long-term debt, partially offset by ~~higher repayments of long-term~~lower debt proceeds (net) year over year and higher 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.

~~Capital Expenditures —~~ ~~The current estimated base capital expenditure programs of Xcel Energy’s operating companies for years 2017 through 2021 are shown in the table below:~~

Capital Forecast
(Millions of Dollars) 2017 2018 2019 2020 2021
2017 - 2021
Total
By Subsidiary
NSP-Minnesota $ 1,195
$ 1,170
$ 1,515
$ 1,405
$ 1,220
$ 6,505
PSCo 1,590
1,670
1,190
1,030
980
6,460
SPS 610
570
490
400
450
2,520
NSP-Wisconsin 250
280
250
280
300
1,360
Other 10
10
510
510
500
1,540
Total capital expenditures $ 3,655
$ 3,700
$ 3,955
$ 3,625
$ 3,450
$ 18,385

Capital Forecast
(Millions of Dollars) 2017 2018 2019 2020 2021
2017 - 2021
Total
By Function
Electric transmission $ 795
$ 840
$ 750
$ 690
$ 805
$ 3,880
Electric distribution 760
865
950
905
955
4,435
Electric generation 670
685
655
405
485
2,900
Natural gas 400
415
420
420
415
2,070
Renewables 610
555
915
925
500
3,505
Other 420
340
265
280
290
1,595
Total capital expenditures $ 3,655
$ 3,700
$ 3,955
$ 3,625
$ 3,450
$ 18,385

The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual capital expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, regulatory decisions, legislative initiatives, reserve margin requirements, the availability of purchased power, alternative plans for meeting long-term energy needs, compliance with environmental requirements, renewable portfolio standards and merger, acquisition and divestiture opportunities. The table above does not include potential expenditures of Xcel Energy’s transmission-only subsidiaries.

~~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. Xcel Energy does not anticipate issuing any equity to fund its capital investment program for 2017-2021. The current estimated financing plans of Xcel Energy Inc. and its subsidiaries for the years 2017 through 2021 are shown in the table below.

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(Millions of Dollars)
Funding Capital Expenditures
Cash from Operations* $ 13,465
New Debt** 4,920
Equity —
2017-2021 Capital Expenditures $ 18,385

Maturing Debt $ 3,550


*	~~Net of dividends.~~


**	~~Reflects a combination of short and long-term debt.~~

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 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 ~~2017.~~2018. 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, hedge fund of funds and commodity investments.

In January ~~2016,~~2017, contributions of ~~$125.0~~$150.0 million were made across four of Xcel Energy’s pension plans;

In ~~2015,~~2016, contributions of ~~$90.0~~$125.2 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 ~~Sept.~~June 30, ~~2016,~~2017, approximately ~~$281.7~~$1.8 million of cash was held in these accounts.

~~Amended~~ Credit ~~Agreements~~Facilities — ~~- In June 2016,~~NSP-Minnesota, NSP-Wisconsin, PSCo, SPS and Xcel Energy Inc.~~, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS entered into amended~~ each have five-year credit agreements with a syndicate of banks. The total borrowing limit under the amended credit agreements remained at $2.75 billion. The amended credit agreements have substantially the same terms and conditions as the prior credit agreements with the following exceptions:

~~The maturity extended from October 2019 to June 2021.~~

~~The commitment fees, calculated on the unused portion~~size of the ~~lines of~~ credit ~~were reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term~~facilities is $2.75 billion and each credit ~~ratings.~~facility terminates in June 2021.

NSP-Minnesota, PSCo, SPS and Xcel Energy Inc.~~, NSP-Minnesota, PSCo, and SPS~~ 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.

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~~Credit Facilities —~~As of ~~Oct.~~July 24, ~~2016,~~2017, 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	$	263	$	737	$	—	$	737	$	1,000	$	483	$	517	$	5	$	522
PSCo	700		22		678		1		679		700		3		697		1		698
NSP-Minnesota	500		11		489		—		489		500		145		355		1		356
SPS	400		5		395		1		396		400		101		299		—		299
NSP-Wisconsin	150		37		113		1		114		150		70		80		—		80
Total	$	2,750	$	338	$	2,412	$	3	$	2,415	$	2,750	$	802	$	1,948	$	7	$	1,955


^(a)	These credit facilities expire in June 2021.


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

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Commercial Paper — 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 outstanding for Xcel Energy was as follows:


(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2016			Year Ended Dec. 31, 2015			Three Months Ended June 30, 2017			Year Ended Dec. 31, 2016
Borrowing limit	$	2,750		$	2,750		$	2,750		$	2,750
Amount outstanding at period end	366			846			784			392
Average amount outstanding	477			601			778			485
Maximum amount outstanding	609			1,360			1,247			1,183
Weighted average interest rate, computed on a daily basis	0.77		%	0.48		%	1.28		%	0.74		%
Weighted average interest rate at period end	0.77			0.82			1.49			0.95

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.

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

~~Xcel Energy Inc. plans to issue approximately $300 million of senior unsecured bonds;~~

~~NSP-Minnesota plans to issue approximately $600 million of first mortgage bonds;~~

~~NSP-Wisconsin plans to issue approximately $100 million of first mortgage bonds;~~

~~PSCo plans to issue approximately $400 million of first mortgage bonds; and~~

~~SPS plans to issue approximately $150 million of first mortgage bonds.~~

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~~During 2016,~~ Xcel Energy Inc. and its utility subsidiaries issued and anticipate issuing the following:

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

~~In May, NSP-Minnesota issued $350 million of 3.6 percent first mortgage bonds due May 15, 2046;~~

~~In June, PSCo issued $250 million of 3.55~~3.80 percent first mortgage bonds due June 15, ~~2046;~~

~~In August, SPS issued $300 million of 3.4 percent first mortgage bonds due Aug. 15, 2046; and~~2047;

Xcel Energy Inc. plans to issue approximately ~~$800~~$300 million of senior ~~notes~~unsecured bonds in the fourth quarter;

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

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

SPS plans to issue approximately $450 million of first mortgage bonds in the third quarter.

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

Off-Balance-Sheet Arrangements

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

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

Xcel Energy’s ~~revised 2016 ongoing earnings guidance is $2.17 to $2.22 per share, compared with the previous issued guidance of $2.12 to $2.27 per share.~~^(a) ~~Key assumptions related to 2016 earnings are detailed below:~~

~~Constructive outcomes in all rate case~~2017 GAAP and ~~regulatory proceedings.~~

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

~~Weather-normalized retail electric utility sales are projected to be relatively flat.~~

~~Weather-normalized retail firm natural gas sales are projected to be relatively flat.~~

~~Capital rider revenue is projected to increase by $35 million to $45 million over 2015 levels.~~

~~The change in O&M expenses is projected to be within a range of 0 percent to 1 percent from 2015 levels.~~

Depreciation expense is projected to increase approximately $185 million to $195 million over 2015 levels. Approximately $20 million of the increased depreciation expense and amortization will be recovered through the renewable development fund rider (not included in the capital rider) in Minnesota.

~~Property taxes are projected to increase approximately $20 million to $25 million over 2015 levels.~~

~~Interest expense (net of AFUDC — debt) is projected to increase $50 million to $60 million over 2015 levels.~~

~~AFUDC — equity is projected to increase approximately $0 million to $10 million from 2015 levels.~~

~~The ETR is projected to be approximately 34 percent to 36 percent.~~

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

~~Xcel Energy’s 2017~~ ongoing earnings guidance is $2.25 to $2.35 per share.^(a) Key assumptions related to 2017 earnings are detailed below:

Constructive outcomes in all rate case and regulatory proceedings.

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

Weather-normalized retail electric utility sales are projected to increase 0 percent to 0.5 percent.

Weather-normalized retail firm natural gas sales are projected to increase 0 percent to 0.5 percent.

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Capital rider revenue is projected to increase by ~~$65~~$50 million to ~~$75~~$60 million over 2016 levels. The change is largely due to the level of PTC, which flows back to customers.

O&M expenses are projected to be flat.

Depreciation expense is projected to increase approximately ~~$160~~$180 million to ~~$170~~$190 million over 2016 levels. The change in depreciation expense is largely due to changes in the amortization of the renewable development fund, which is offset in revenue and will not have an impact on earnings.

Property taxes are projected to increase approximately $0 million to $10 million over 2016 levels.

Interest expense (net of AFUDC — debt) is projected to increase $5$15 million to ~~$15~~$25 million over 2016 levels.

AFUDC — equity is projected to increase approximately ~~$10~~$5 million to ~~$20~~$15 million from 2016 levels.

The ETR is projected to be approximately 3231 percent to 3433 percent. The change is largely due to the level of PTC, which flows back to customers.

Average common stock and equivalents are projected to be approximately 509 million shares.

^(a)

~~Given the~~Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown ~~nature of adjustments that may be necessary to reconcile ongoing diluted EPS to GAAP diluted EPS,~~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.

~~Table of Contents~~

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 4 percent to 6 ~~percent, based on ongoing 2015 EPS of $2.10;~~percent;

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 of ongoing operations.

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 ~~Sept.~~June 30, ~~2016,~~2017, 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

~~Effective January~~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 ~~(ERP)~~ system to improve certain financial and related transaction processes. ~~During 2016 and 2017,~~ Xcel Energy ~~will continue implementing~~is continuing to implement additional modules ~~and expects to begin~~including the conversion of existing work management systems to this ~~new ERP system.~~same system during 2017. In connection with this ongoing implementation, Xcel Energy ~~has updated and will continue~~is updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting ~~procedures.~~systems. Xcel Energy does not ~~expect the~~believe that this implementation ~~of the additional modules to materially affect~~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, ~~2015,~~2016, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

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 ~~Sept.~~June 30, ~~2016:~~2017:

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
July 1, 2016 — July 31, 2016 —
$ —
—
—
Aug. 1, 2016 — Aug. 31, 2016 ^(a)
47,802
42.22
—
—
Sept. 1, 2016 — Sept. 30, 2016 —
—
—
—
Total 47,802
—
—

^(a)

~~Xcel Energy Inc.~~

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 ~~one~~Programs

Maximum Number (or Approximate Dollar Value) of ~~its agents periodically purchases common shares in order to satisfy obligations under~~Shares That May Yet Be Purchased Under the ~~Stock Equivalent Plan for Non-Employee Directors.~~Plans or Programs

April 1, 2017 — April 30, 2017

—

May 1, 2017 — May 31, 2017

—

June 1, 2017 — June 30, 2017

—

Total

—

~~Item 4~~ — ~~MINE SAFETY DISCLOSURES~~

~~None.~~

~~Item 5~~ — ~~OTHER INFORMATION~~

~~None.~~

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Item 6 — EXHIBITS

* Indicates incorporation by reference

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



3.01*	Amended and Restated Articles of Incorporation of Xcel Energy Inc., as filed on May ~~17,~~18, 2012 (Exhibit 3.01 to Form 8-K dated May 16, 2012 (file no. 001-03034)).
3.02*	Bylaws of Xcel Energy Inc. ~~Bylaws,~~, as amended on Feb. 17, 2016 (Exhibit 3.01 to Form 8-K dated Feb. ~~17,~~18, 2016 (file no. 001-03034)).
4.01*	Supplemental Indenture No. 27 dated as of ~~Aug.~~June 1, ~~2016~~2017 between ~~SPS~~PSCo and U.S. Bank National Association, as Trustee, creating ~~$300,000,000~~$400 million principal amount of ~~3.40~~3.80 percent First Mortgage Bonds, Series No. 430 due ~~2046.~~2047. (Exhibit ~~4.02~~4.01 to Form 8-K of ~~SPS~~PSCo dated ~~Aug. 12, 2016~~June 19, 2017 (file no. ~~001-03789)~~001-03280)).
~~10.01+~~	~~Third Amendment dated Sept. 30, 2016 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement).~~
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 ~~Sept.~~June 30, ~~2016~~2017 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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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.

~~Oct.~~July 28, ~~2016~~2017	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)

6055



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



Electric Rate Request (Millions of Dollars)	NSP-Wisconsin Request			Staff Recommendation			Final Decision
Rate base investments	$	11.0		$	7.6		7.6
Generation and transmission expenses (excluding fuel and purchased power) ^(a)	6.8			6.1			6.1
Fuel and purchased power expenses	11.0			7.7			10.7
Subtotal	28.8			21.4			24.4
2015 fuel refund ^(b)	(9.5		)	—			—
Department of Energy settlement refund	(1.9		)	(1.9		)	(1.9		)
Total electric rate increase	$	17.4		$	19.5		$	22.5



	Capital Forecast
(Millions of Dollars)	2017		2018		2019		2020		2021		2017 - 2021 Total
By Subsidiary
NSP-Minnesota	$	1,195	$	1,170	$	1,515	$	1,405	$	1,220	$	6,505
PSCo	1,590		1,670		1,190		1,030		980		6,460
SPS	610		570		490		400		450		2,520
NSP-Wisconsin	250		280		250		280		300		1,360
Other	10		10		510		510		500		1,540
Total capital expenditures	$	3,655	$	3,700	$	3,955	$	3,625	$	3,450	$	18,385



(Millions of Dollars)
Funding Capital Expenditures
Cash from Operations*	$	13,465
New Debt**	4,920
Equity	—
2017-2021 Capital Expenditures	$	18,385

Maturing Debt	$	3,550