UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended June 30, ~~2015~~2016



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

Commission File Number: 001-3034

Xcel Energy Inc.

(Exact name of registrant as specified in its charter)



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

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

(612) 330-5500

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer x		Accelerated filer ¨
Non-accelerated filer ¨		Smaller reporting company ¨
(Do not check if smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.



Class		Outstanding at ~~July 27, 2015~~August 1, 2016
Common Stock, $2.50 par value		~~507,211,342~~507,952,795 shares

TABLE OF CONTENTS



PART I	FINANCIAL INFORMATION
Item 1 —	Financial Statements (unaudited)	3
	CONSOLIDATED STATEMENTS OF INCOME	3
	CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME	4
	CONSOLIDATED STATEMENTS OF CASH FLOWS	5
	CONSOLIDATED BALANCE SHEETS	6
	CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY	7
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	9
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	4237
Item 3 —	Quantitative and Qualitative Disclosures about Market Risk	5954
Item 4 —	Controls and Procedures	5954

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	6054
Item 1A —	Risk Factors	6054
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	6055
Item 4 —	Mine Safety Disclosures	6055
Item 5 —	Other Information	6055
Item 6 —	Exhibits	6156

SIGNATURES		6257

	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 June 30						Six Months Ended June 30						Three Months Ended June 30						Six Months Ended June 30
	2015			2014			2015			2014			2016			2015			2016			2015
Operating revenues
Electric	$	2,213,460		$	2,297,638		$	4,438,323		$	4,599,348		$	2,224,142		$	2,213,460		$	4,409,261		$	4,438,323
Natural gas	284,131			369,127			1,000,127			1,248,815			258,899			284,131			824,588			1,000,127
Other	17,543			18,331			38,903			39,537			16,808			17,543			38,273			38,903
Total operating revenues	2,515,134			2,685,096			5,477,353			5,887,700			2,499,849			2,515,134			5,272,122			5,477,353

Operating expenses
Electric fuel and purchased power	904,705			1,041,322			1,854,837			2,108,643			855,968			904,705			1,717,820			1,854,837
Cost of natural gas sold and transported	126,667			210,901			599,038			834,729			90,071			126,667			402,188			599,038
Cost of sales — other	8,164			7,642			18,213			16,771			8,332			8,164			16,577			18,213
Operating and maintenance expenses	594,279			585,604			1,180,109			1,145,747			596,978			594,279			1,174,388			1,180,109
Conservation and demand side management program expenses	54,141			70,834			107,946			148,380			55,916			54,141			113,352			107,946
Depreciation and amortization	274,602			255,307			547,700			501,250			322,534			274,602			642,554			547,700
Taxes (other than income taxes)	129,731			116,278			266,357			240,980			138,469			129,731			283,792			266,357
Loss on Monticello life cycle management/extended power uprate project	—			—			129,463			—			—			—			—			129,463
Total operating expenses	2,092,289			2,287,888			4,703,663			4,996,500			2,068,268			2,092,289			4,350,671			4,703,663

Operating income	422,845			397,208			773,690			891,200			431,581			422,845			921,451			773,690

Other income, net	961			82			4,122			3,283			1,560			961			5,810			4,122
Equity earnings of unconsolidated subsidiaries	8,422			7,811			16,198			15,249			9,617			8,422			22,799			16,198
Allowance for funds used during construction — equity	12,641			23,608			25,301			45,515			14,730			12,641			27,843			25,301

Interest charges and financing costs
Interest charges — includes other financing costs of $5,861, $5,614, $11,559 and $11,406, respectively	144,222			139,400			289,162			278,494
Interest charges — includes other financing costs of $6,630 $5,861, $12,966 and $11,559, respectively													162,980			144,222			319,423			289,162
Allowance for funds used during construction — debt	(6,165		)	(10,113		)	(12,309		)	(19,661		)	(6,684		)	(6,165		)	(12,674		)	(12,309		)
Total interest charges and financing costs	138,057			129,287			276,853			258,833			156,296			138,057			306,749			276,853

Income before income taxes	306,812			299,422			542,458			696,414			301,192			306,812			671,154			542,458
Income taxes	109,881			104,258			193,461			240,029			104,397			109,881			233,047			193,461
Net income	$	196,931		$	195,164		$	348,997		$	456,385		$	196,795		$	196,931		$	438,107		$	348,997

Weighted average common shares outstanding:
Basic	507,707			503,272			507,359			501,408			508,930			507,707			508,789			507,359
Diluted	508,074			503,456			507,747			501,612			509,490			508,074			509,311			507,747

Earnings per average common share:
Basic	$	0.39		$	0.39		$	0.69		$	0.91		$	0.39		$	0.39		$	0.86		$	0.69
Diluted	0.39			0.39			0.69			0.91			0.39			0.39			0.86			0.69

Cash dividends declared per common share	$	0.32		$	0.30		$	0.64		$	0.60		$	0.34		$	0.32		$	0.68		$	0.64

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 June 30				Six Months Ended June 30				Three Months Ended June 30				Six Months Ended June 30
	2015		2014		2015		2014		2016		2015		2016		2015
Net income	$	196,931	$	195,164	$	348,997	$	456,385	$	196,795	$	196,931	$	438,107	$	348,997

Other comprehensive income

Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $561, $550, $1,130 and $1,099, respectively	883		864		1,759		1,728
Amortization of losses included in net periodic benefit cost, net of tax of $550, $561, $407 and $1,130, respectively									865		883		1,076		1,759

Derivative instruments:
Net fair value increase, net of tax of $11, $9, $4 and $6, respectively	18		16		7		8
Reclassification of losses to net income, net of tax of $382, $365, $764 and $722, respectively	600		574		1,185		1,135
Net fair value increase, net of tax of $7, $11, $5 and $4, respectively									12		18		8		7
Reclassification of losses to net income, net of tax of $594, $382, $1,198 and $764, respectively									936		600		1,874		1,185
	618		590		1,192		1,143		948		618		1,882		1,192
Marketable securities:
Net fair value increase, net of tax of $1, $0, $1 and $24, respectively	1		—		2		38
Net fair value increase, net of tax of $0, $1, $0 and $1, respectively									—		1		—		2

Other comprehensive income	1,502		1,454		2,953		2,909		1,813		1,502		2,958		2,953
Comprehensive income	$	198,433	$	196,618	$	351,950	$	459,294	$	198,608	$	198,433	$	441,065	$	351,950

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)

	Six Months Ended June 30						Six Months Ended June 30
	2015			2014			2016			2015
Operating activities
Net income	$	348,997		$	456,385		$	438,107		$	348,997
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	556,420			509,914			650,336			556,420
Conservation and demand side management program amortization	2,901			3,131			2,323			2,901
Nuclear fuel amortization	49,454			60,466			58,267			49,454
Deferred income taxes	191,164			236,479			252,889			191,164
Amortization of investment tax credits	(2,768		)	(2,886		)	(2,613		)	(2,768		)
Allowance for equity funds used during construction	(25,301		)	(45,515		)	(27,843		)	(25,301		)
Equity earnings of unconsolidated subsidiaries	(16,198		)	(15,249		)	(22,799		)	(16,198		)
Dividends from unconsolidated subsidiaries	19,754			18,114			22,910			19,754
Share-based compensation expense	21,420			10,990			24,454			21,420
Loss on Monticello life cycle management/extended power uprate project	129,463			—			—			129,463
Net realized and unrealized hedging and derivative transactions	13,450			(2,403		)	3,903			13,450
Other							(388		)	—
Changes in operating assets and liabilities:
Accounts receivable	150,283			1,406			35,042			150,283
Accrued unbilled revenues	145,781			77,557			65,159			145,781
Inventories	64,561			75,268			81,880			64,561
Other current assets	69,080			(32,157		)	69,493			69,080
Accounts payable	(132,032		)	(147,734		)	27,805			(132,032		)
Net regulatory assets and liabilities	129,595			63,675			34,264			129,595
Other current liabilities	(92,108		)	(129,981		)	(164,076		)	(92,108		)
Pension and other employee benefit obligations	(78,681		)	(115,455		)	(108,562		)	(78,681		)
Change in other noncurrent assets	684			47,855			(6,363		)	684
Change in other noncurrent liabilities	(36,874		)	(30,349		)	(21,649		)	(36,874		)
Net cash provided by operating activities	1,509,045			1,039,511			1,412,539			1,509,045

Investing activities
Utility capital/construction expenditures	(1,477,959		)	(1,575,748		)	(1,413,129		)	(1,477,959		)
Proceeds from insurance recoveries	27,237			6,000			1,595			27,237
Allowance for equity funds used during construction	25,301			45,515			27,843			25,301
Purchases of investments in external decommissioning fund	(640,100		)	(404,780		)
Proceeds from the sale of investments in external decommissioning fund	636,669			401,488
Investment in WYCO Development LLC	(764		)	(2,132		)
Purchases of investment securities							(319,880		)	(640,100		)
Proceeds from the sale of investment securities							262,321			636,669
Investments in WYCO Development LLC and other							(2,170		)	(764		)
Other, net	(1,407		)	(1,568		)	100			(1,407		)
Net cash used in investing activities	(1,431,023		)	(1,531,225		)	(1,443,320		)	(1,431,023		)

Financing activities
(Repayments of) proceeds from short-term borrowings, net	(568,500		)	18,800
Repayments of short-term borrowings, net							(399,000		)	(568,500		)
Proceeds from issuance of long-term debt	841,534			838,582			1,337,430			841,534
Repayments of long-term debt	(454		)	(275,484		)	(579,976		)	(454		)
Proceeds from issuance of common stock	3,409			176,573			—			3,409
Purchase of common stock for settlement of equity awards							(789		)	—
Dividends paid	(298,022		)	(274,361		)	(335,113		)	(298,022		)
Net cash (used in) provided by financing activities	(22,033		)	484,110
Net cash provided by (used in) financing activities							22,552			(22,033		)

Net change in cash and cash equivalents	55,989			(7,604		)	(8,229		)	55,989
Cash and cash equivalents at beginning of period	79,608			107,144			84,940			79,608
Cash and cash equivalents at end of period	$	135,597		$	99,540		$	76,711		$	135,597

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(266,840	)	$	(251,461	)	$	(293,954	)	$	(266,840	)
Cash received (paid) for income taxes, net	58,598			(4,704		)
Cash received for income taxes, net							61,345			58,598

Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable	$	206,540		$	305,447		$	252,370		$	206,540
Issuance of common stock for reinvested dividends and 401(k) plans	30,498			29,272			13,497			30,498

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)

	June 30, 2015			Dec. 31, 2014			June 30, 2016			Dec. 31, 2015
Assets
Current assets
Cash and cash equivalents	$	135,597		$	79,608		$	76,711		$	84,940
Accounts receivable, net	676,223			826,506			689,564			724,606
Accrued unbilled revenues	582,711			728,492			589,708			654,867
Inventories	532,703			597,183			526,785			608,584
Regulatory assets	364,746			444,058			325,690			344,630
Derivative instruments	63,603			85,723			46,953			33,842
Deferred income taxes	429,860			246,210			206,644			140,219
Prepaid taxes	121,705			185,488			115,898			163,023
Prepayments and other	141,774			171,112			126,146			155,734
Total current assets	3,048,922			3,364,380			2,704,099			2,910,445

Property, plant and equipment, net	29,350,364			28,756,916			31,823,282			31,205,851

Other assets
Nuclear decommissioning fund and other investments	1,880,153			1,832,640			1,987,474			1,902,995
Regulatory assets	2,759,892			2,774,216			2,886,250			2,858,741
Derivative instruments	53,306			53,775			50,644			51,083
Other	176,172			175,957			38,415			32,581
Total other assets	4,869,523			4,836,588			4,962,783			4,845,400
Total assets	$	37,268,809		$	36,957,884		$	39,490,164		$	38,961,696

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	707,356		$	257,726		$	710,151		$	657,021
Short-term debt	451,000			1,019,500			447,000			846,000
Accounts payable	830,278			1,173,006			921,973			960,982
Regulatory liabilities	418,618			410,729			279,755			306,830
Taxes accrued	280,838			396,615			330,398			438,189
Accrued interest	160,146			158,536			169,309			166,829
Dividends payable	162,224			151,720			172,704			162,410
Derivative instruments	26,845			21,632			26,542			29,839
Other	499,946			475,119			448,549			490,197
Total current liabilities	3,537,251			4,064,583			3,506,381			4,058,297

Deferred credits and other liabilities
Deferred income taxes	6,249,511			5,852,988			6,619,681			6,293,661
Deferred investment tax credits	70,928			73,696			65,806			68,419
Regulatory liabilities	1,176,806			1,163,429			1,343,889			1,332,889
Asset retirement obligations	2,517,668			2,446,631			2,671,320			2,608,562
Derivative instruments	171,691			183,936			156,357			168,311
Customer advances	241,546			256,945			212,565			228,999
Pension and employee benefit obligations	858,450			936,907			825,614			941,002
Other	279,766			264,653			280,647			261,756
Total deferred credits and other liabilities	11,566,366			11,179,185			12,175,879			11,903,599

Commitments and contingencies
Capitalization
Long-term debt	11,896,126			11,499,634			13,104,770			12,398,880
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 506,959,395 and 505,733,267 shares outstanding at June 30, 2015 and Dec. 31, 2014, respectively	1,267,398			1,264,333
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,952,795 and 507,535,523 shares outstanding at June 30, 2016 and Dec. 31, 2015, respectively							1,269,882			1,268,839
Additional paid in capital	5,863,209			5,837,330			5,896,394			5,889,106
Retained earnings	3,243,645			3,220,958			3,643,653			3,552,728
Accumulated other comprehensive loss	(105,186		)	(108,139		)	(106,795		)	(109,753		)
Total common stockholders’ equity	10,269,066			10,214,482			10,703,134			10,600,920
Total liabilities and equity	$	37,268,809		$	36,957,884		$	39,490,164		$	38,961,696

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 June 30, 2015 and 2014						Retained Earnings
Balance at March 31, 2014	501,152	$	1,252,879	$	5,681,150	$	2,918,215			Accumulated Other Comprehensive Loss	$	(104,820	)		$	9,747,424
Net income						195,164								195,164
Other comprehensive income										1,454				1,454
Dividends declared on common stock						(151,973		)						(151,973		)
Issuances of common stock	3,954	9,885		111,053										120,938
Share-based compensation				7,765										7,765
Balance at June 30, 2014	505,106	$	1,262,764	$	5,799,968	$	2,961,406			$	(103,366	)		$	9,920,772

Three Months Ended June 30, 2016 and 2015																	Three Months Ended June 30, 2016 and 2015
Balance at March 31, 2015	506,664	$	1,266,659	$	5,844,995	$	3,209,904			$	(106,688	)		$	10,214,870		506,664	$	1,266,659	$	5,844,995		$	3,209,904		$	(106,688	)	$	10,214,870
Net income						196,931								196,931									196,931						196,931
Other comprehensive income										1,502				1,502												1,502			1,502
Dividends declared on common stock						(163,190		)						(163,190		)							(163,190		)				(163,190		)
Issuances of common stock	295	739		9,316										10,055			295	739		9,316									10,055
Share-based compensation				8,898										8,898						8,898									8,898
Balance at June 30, 2015	506,959	$	1,267,398	$	5,863,209	$	3,243,645			$	(105,186	)		$	10,269,066		506,959	$	1,267,398	$	5,863,209		$	3,243,645		$	(105,186	)	$	10,269,066

Balance at March 31, 2016																	507,953	$	1,269,882	$	5,889,939		$	3,620,421		$	(108,608	)	$	10,671,634
Net income																							196,795						196,795
Other comprehensive income																										1,813			1,813
Dividends declared on common stock																							(173,563		)				(173,563		)
Issuances of common stock																	—	—		(187		)							(187		)
Share-based compensation																				6,642									6,642
Balance at June 30, 2016																	507,953	$	1,269,882	$	5,896,394		$	3,643,653		$	(106,795	)	$	10,703,134

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			Common Stock Issued						Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Stockholders’ Equity
	Shares	Par Value		Additional Paid In Capital					Shares								Par Value		Additional Paid In Capital
Six Months Ended June 30, 2015 and 2014
Balance at Dec. 31, 2013	497,972	$	1,244,929	$	5,619,313	$	2,807,983				$	(106,275	)		$	9,565,950
Net income						456,385								456,385
Other comprehensive income										2,909				2,909
Dividends declared on common stock						(302,962		)						(302,962		)
Issuances of common stock	7,134	17,835		166,825										184,660
Share-based compensation				13,830										13,830
Balance at June 30, 2014	505,106	$	1,262,764	$	5,799,968	$	2,961,406			$	(103,366	)		$	9,920,772

Six Months Ended June 30, 2016 and 2015																	Six Months Ended June 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		505,733	$	1,264,333	$	5,837,330		$	3,220,958		$	(108,139	)	$	10,214,482
Net income						348,997								348,997									348,997						348,997
Other comprehensive income										2,953				2,953												2,953			2,953
Dividends declared on common stock						(326,310		)						(326,310		)							(326,310		)				(326,310		)
Issuances of common stock	1,226	3,065		10,209										13,274			1,226	3,065		10,209									13,274
Share-based compensation				15,670										15,670						15,670									15,670
Balance at June 30, 2015	506,959	$	1,267,398	$	5,863,209	$	3,243,645			$	(105,186	)		$	10,269,066		506,959	$	1,267,398	$	5,863,209		$	3,243,645		$	(105,186	)	$	10,269,066

Balance at Dec. 31, 2015																	507,536	$	1,268,839	$	5,889,106		$	3,552,728		$	(109,753	)	$	10,600,920
Net income																							438,107						438,107
Other comprehensive income																										2,958			2,958
Dividends declared on common stock																							(347,182		)				(347,182		)
Issuances of common stock																	417	1,043		(3,942		)							(2,899		)
Purchase of common stock for settlement of equity awards																				(789		)							(789		)
Share-based compensation																				12,019									12,019
Balance at June 30, 2016																	507,953	$	1,269,882	$	5,896,394		$	3,643,653		$	(106,795	)	$	10,703,134

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 June 30, ~~2015~~2016 and Dec. 31, ~~2014;~~2015; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three and six months ended June 30, ~~2015~~2016 and ~~2014;~~2015; and its cash flows for the six months ended June 30, ~~2015~~2016 and ~~2014.~~2015. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, ~~2015~~2016 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, ~~2014~~2015 balance sheet information has been derived from the audited ~~2014~~2015 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2014.~~2015. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2014,~~2015, filed with the SEC on Feb. ~~20, 2015.~~19, 2016. Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.


1.	Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2014,~~2015, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2.	Accounting Pronouncements

Recently Issued

Revenue Recognition — In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. ~~As a result of the FASB’s deferral of the standard’s required implementation date in July 2015, the~~The guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. Xcel Energy is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

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

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

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

Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU 2016-09), which amends existing guidance to simplify several aspects of accounting and presentation for share-based payment transactions, including the accounting for income taxes and forfeitures, as well as presentation in the statement of cash flows. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Xcel Energy does not expect the implementation of ASU 2016-09 to have a material impact on its consolidated financial statements.

Recently Adopted

Consolidation — In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. ~~This guidance will be effective for interim and annual reporting periods beginning after Dec. 15. 2015, and early adoption is permitted.~~ Xcel Energy ~~is currently evaluating~~implemented the ~~impact~~guidance on Jan. 1, 2016, and other than the classification of ~~adopting ASU 2015-02~~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 ~~amends existing guidance to require~~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. ~~This~~Xcel Energy implemented the new guidance ~~will be effective for interim~~as required on Jan. 1, 2016, and ~~annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than~~as a result, $94.5 million of deferred debt issuance costs were presented as a deduction from the ~~prescribed reclassification~~carrying amount of ~~assets to an offset of~~long-term debt on the consolidated balance ~~sheets, Xcel Energy does not expect~~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 ~~implementation~~consolidated balance sheet as of ~~ASU 2015-03 to have a material impact on its consolidated financial statements.~~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 ~~(Accounting Standards Update (ASU)~~(ASU No. 2015-07), which ~~removes~~eliminates the requirement to categorize ~~within the~~ fair value ~~hierarchy the fair values for investments measured~~measurements using a net asset value ~~methodology. This guidance will be effective on a retrospective basis for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than~~(NAV) methodology in the ~~reduced disclosure requirements,~~fair value hierarchy. Xcel Energy ~~does not expect~~implemented the guidance on Jan. 1, 2016, and the implementation ~~of ASU 2015-07 to~~did not have a material impact on its consolidated financial statements. For related disclosures, see Note 8 to the consolidated financial statements.

~~Table of Contents~~


3.	Selected Balance Sheet Data


(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014			June 30, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	726,732		$	884,225		$	735,586		$	776,494
Less allowance for bad debts	(50,509		)	(57,719		)	(46,022		)	(51,888		)
	$	676,223		$	826,506		$	689,564		$	724,606


(Thousands of Dollars)	June 30, 2015		Dec. 31, 2014		June 30, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	256,000	$	244,099	$	304,055	$	290,690
Fuel	203,177		183,249		164,054		202,271
Natural gas	73,526		169,835		58,676		115,623
	$	532,703	$	597,183	$	526,785	$	608,584

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(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014			June 30, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	33,996,892		$	33,203,139		$	36,990,529		$	36,464,050
Natural gas plant	4,726,068			4,643,452			5,065,218			4,944,757
Common and other property	1,623,828			1,611,486			1,746,789			1,709,508
Plant to be retired ^(a)	55,397			71,534			29,853			38,249
Construction work in progress	2,092,391			2,005,531			1,687,397			1,256,949
Total property, plant and equipment	42,494,576			41,535,142			45,519,786			44,413,513
Less accumulated depreciation	(13,543,351		)	(13,168,418		)	(14,035,591		)	(13,591,259		)
Nuclear fuel	2,405,823			2,347,422			2,461,008			2,447,251
Less accumulated amortization	(2,006,684		)	(1,957,230		)	(2,121,921		)	(2,063,654		)
	$	29,350,364		$	28,756,916		$	31,823,282		$	31,205,851


^(a)	In 2017, PSCo ~~has received approval for~~expects to both early ~~retirement of Cherokee Unit 3 and~~retire Valmont Unit 5 ~~between 2015~~ and ~~2017.~~convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC). Amounts are presented net of accumulated depreciation.


4.	Income Taxes

Except to the extent noted below, Note 6 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2014~~2015 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

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

Federal Audit — Xcel Energy files a consolidated federal income tax return. ~~The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in March 2016.~~ In ~~the third quarter of~~ 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of June 30, ~~2015,~~2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in ~~$12~~$14 million of income tax expense for the 2009 through 2011 and 2013 claims, the recently filed ~~2013~~2014 claim, and the anticipated claim for ~~2014. As~~2015. In the fourth quarter of ~~June 30,~~ 2015, the IRS ~~has begun~~forwarded the ~~appeals process;~~issue to the Office of Appeals (Appeals). In the second quarter of 2016 the IRS audit team presented their case to Appeals; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the Appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of June 30, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. As of June 30, ~~2015,~~2016, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows:



State		Year
Colorado		2009
Minnesota		2009
Texas		2009
Wisconsin		~~2010~~2011

In February 2016, Texas began an audit of years 2009 and 2010. As of June 30, ~~2015,~~2016, Texas had not proposed any adjustments.

In June 2016, Minnesota began an audit of years 2010 through 2014. As of June 30, 2016, Minnesota had not proposed any adjustments. As of June 30, 2016, 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). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

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


(Millions of Dollars)	June 30, 2015		Dec. 31, 2014		June 30, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	16.4	$	16.2	$	26.8	$	25.8
Unrecognized tax benefit — Temporary tax positions	56.9		50.3		97.6		94.9
Total unrecognized tax benefit	$	73.3	$	66.5	$	124.4	$	120.7

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


(Millions of Dollars)	June 30, 2015			Dec. 31, 2014			June 30, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(35.2	)	$	(28.5	)	$	(40.4	)	$	(36.7	)

It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS ~~appeals process progresses~~Appeals and audit progress, the Minnesota and Texas audits progress, and other state audits resume. As the IRS ~~appeals process moves closer to completion,~~Appeals and IRS, Minnesota, and Texas audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately ~~$10~~$58 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at June 30, ~~2015~~2016 and Dec. 31, ~~2014~~2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, ~~2015~~2016 or Dec. 31, ~~2014.~~2015.


5.	Rate Matters

Except to the extent noted below, the circumstances set forth in Note 12 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2014~~2015 and in Note 5 to Xcel Energy Inc.’s Quarterly Report on

Form 10-Q for the quarterly period ended March 31, ~~2015,~~2016, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

NSP-Minnesota

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

~~NSP-Minnesota –~~ Minnesota ~~2014~~2016 Multi-Year Electric Rate Case — In November ~~2013,~~2015, NSP-Minnesota filed a ~~two-year~~three-year electric rate case with the MPUC. The rate case ~~was~~is based on a requested return on equity (ROE) of ~~10.25~~10.0 percent and a ~~52.5~~52.50 percent equity ratio, a 2014 average electric rate base of $6.67 billion and an additional average rate base of $412 million in 2015. The NSP-Minnesota electric rate case initially reflected a requested increase in revenues of approximately $193 million, or 6.9 percent, in 2014 and an additional $98 million, or 3.5 percent, in 2015.ratio. The request ~~included a proposed rate moderation plan for 2014 and 2015.~~ 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 ~~2013,~~2015, the MPUC approved interim rates ~~of $127 million, effective Jan. 3, 2014, subject to refund.~~for 2016.

~~In 2014, NSP-Minnesota revised its requested rate increase to $115.3 million for 2014 and to $106.0 million for 2015, for a total combined unadjusted increase of $221.3 million.~~

In May 2015, the MPUC ordered a 2014 rate increase and a 2015 step increase. The total increase was estimated to be $166 million, or 5.9 percent, based on a 9.72 percent ROE and 52.50 percent equity ratio. The MPUC also approved a three-year, decoupling pilot with a 3 percent cap on base revenue for the residential and small commercial and industrial classes, based on actual sales, effective Jan. 1, 2016. The decoupling mechanism would eliminate the impact of changes in electric sales due to conservation and weather variability for these classes.

~~Table of Contents~~

In July 2015, the MPUC deliberated on requests for reconsideration of its order. The MPUC determined the Monticello Extended Power Uprate (EPU) project is not used-and-useful until final approval related to the full EPU uprate condition is received from the Nuclear Regulatory Commission (NRC). NSP-Minnesota expects that $13.8 million will be excluded from final rates, as approval from the NRC had not been received as of June 30, 2015. Monticello achieved the full EPU uprate level of 671 megawatts (MW) in June 2015 and received final NRC compliance approval in July 2015, thereby satisfying the used-and-useful conditions established by the MPUC. The MPUC also approved 2015 interim rates effective March 3, 2015 and stated that the 2014 interim rate refund obligation be netted against the 2015 interim rate revenue under-collections.

The MPUC’s decision resulted in an estimated 2015 annual rate increase of $149.4 million or 5.3 percent. NSP-Minnesota anticipates reducing the 2014 refund obligation by approximately $6 million for the change in the interest rate applied to interim refunds and other items.

~~The following tables outline NSP-Minnesota’s filed request and the impact of the MPUC’s decisions made in May and July:~~

2014 Rate Request (Millions of Dollars) NSP-Minnesota MPUC May Decision
NSP-Minnesota’s filed rate request $ 192.7
$ 192.7
Sales forecast (with true-up to 12 months of actual weather-normalized sales) (38.5 ) (37.5 )
ROE —
(31.9 )
Monticello EPU cost recovery (12.2 ) (37.6 )
Property taxes (with true-up to actual 2014 accruals) (13.2 ) (13.2 )
Prairie Island EPU cost recovery (5.1 ) (5.0 )
Health care, pension and other benefits (1.9 ) (3.1 )
Other, net (6.5 ) (5.5 )
Total 2014 $ 115.3
$ 58.9

2015 Rate Request (Millions of Dollars) NSP-Minnesota MPUC May Decision
NSP-Minnesota’s filed rate request $ 98.5
$ 98.5
Monticello EPU cost recovery 11.7
35.4
Depreciation / Retirements —
(0.5 )
Property taxes (3.3 ) (3.3 )
Production tax credits to be included in base rates (11.1 ) (11.1 )
U.S. Department of Energy (DOE) settlement proceeds 10.1
10.1
Emission chemicals (1.6 ) (1.6 )
Other, net 1.7
(2.3 )
Total 2015 step increase - prior to Monticello Life Cycle Management (LCM)/EPU cost
disallowance $ 106.0
$ 125.2

Total for 2014 and 2015 step increase - prior to Monticello LCM/EPU cost disallowance $ 221.3
$ 184.1
Monticello LCM/EPU cost disallowance —
(18.0 )
Total for 2014 and 2015 step increase - including Monticello LCM/EPU cost disallowance $ 221.3
$ 166.1

(Millions of Dollars) MPUC July Decision
2015 annual rate increase - based on MPUC May order $ 166.1
Reconsideration/clarification adjustments:
2015 Monticello EPU used-and-useful adjustment (13.8 )
2014 property tax final true-up (3.1 )
Other, net 0.2
Total 2015 annual rate increase $ 149.4
Impact of interim rate effective March 3, 2015 (3.6 )
Estimated 2015 revenue impact $ 145.8

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Intervenor Testimony:

In June 2016, intervening parties filed direct testimony proposing modifications to NSP-Minnesota’s rate request. The Minnesota Department of Commerce (DOC) subsequently filed revised testimony recommending an increase of approximately $45.6 million in 2016, a step increase of $53.8 million for 2017, and a step decrease of $5.0 million for 2018, based on a recommended ROE of 9.06 percent and an equity ratio of 52.50 percent.

Based on NSP-Minnesota’s interpretation of the DOC’s testimony, certain recommended adjustments of approximately $72.7 million would not be expected to impact earnings, assuming MPUC approval. The following table summarizes NSP-Minnesota’s estimate of the DOC’s recommendations:



(Millions of Dollars)	2016			2017 Step			2018 Step			Total
Filed rate request	$	194.6		$	52.1		$	50.4		$	297.1

DOC recommended adjustments:
ROE	(65.0		)	0.3			1.0			(63.7		)
Sales forecast	(39.4		)	—			—			(39.4		)
Property tax	(5.2		)	(0.3		)	(0.1		)	(5.6		)
Depreciation life	(8.0		)	0.4			(2.2		)	(9.8		)
Purchased demand timing changes	—			—			(19.4		)	(19.4		)
Nuclear capital costs	(3.6		)	0.8			(11.2		)	(14.0		)
Tax related items	(12.2		)	18.4			(6.9		)	(0.7		)
Operating and maintenance (O&M)	(15.5		)	(17.8		)	(16.7		)	(50.0		)
Other, net	(0.1		)	(0.1		)	0.1			(0.1		)
Total DOC Adjustments	(149.0		)	1.7			(55.4		)	(202.7		)

Total DOC recommended rate increase	$	45.6		$	53.8		$	(5.0	)	$	94.4
Estimated non-earnings DOC adjustments:
Depreciation life	8.0			(0.4		)	2.2			9.8
Sales forecast	37.4			—			—			37.4
Property tax	5.2			0.3			0.1			5.6
Purchased demand timing changes	—			—			19.4			19.4
Other	0.5			—			—			0.5
Total estimated non-earnings adjustments	51.1			(0.1		)	21.7			72.7
Total pre-tax earnings impact	$	96.7		$	53.7		$	16.7		$	167.1

The DOC also presented several nuclear recommendations related to capital recovery for spent fuel storage investments and Prairie Island LCM projects.

The use of certificate of need estimates as a recovery cap, and/or provisionally exclude recovery of amounts in excess of the cap unless the costs are deemed reasonable by the DOC’s nuclear consultant and/or the MPUC.

No recovery of a portion of capital costs associated with Monticello fuel storage Cask 16, representing the amount beyond the originally anticipated project cost, or approximately $15 million. The additional costs incurred were for testing of cask lid welds to demonstrate compliance with Nuclear Regulatory Commission requirements.

Settlement Agreement

In August 2016, NSP-Minnesota reached a settlement in principal with several of the parties, which resolves all revenue requirement issues in dispute. The terms and conditions of the agreement are still subject to final documentation. The settlement agreement requires the approval of the MPUC.

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

Rebuttal testimony — Aug. 9, 2016;

Surrebuttal testimony — Sept. 16, 2016;

Settlement conference — Sept. 26, 2016;

Evidentiary hearing — Oct. 4-7, 2016;

Administrative Law Judge report — Feb. 21, 2017; and

MPUC order — June 1, 2017.

A current liability representing NSP-Minnesota’s best estimate of a refund obligation for 2016 associated with interim rates was recorded as of June 30, 2016.

NSP-Minnesota – Gas Utility Infrastructure Costs (GUIC) Rider —In July 2016, the MPUC verbally approved NSP-Minnesota’s request to recover approximately $15 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, as proposed by the DOC. Recovery was approved for the 15-month period from January 2016 to March 2017.

Annual Automatic Adjustment (AAA) of Charges — In June 2016, the 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. As it pertains to NSP-Minnesota, the DOC’s recommendation could impact replacement power cost recovery for the Prairie Island (PI) nuclear facility outages allocated to the Minnesota jurisdiction during the 2015 AAA fiscal year. NSP-Minnesota expects a MPUC decision in mid-2017.

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

In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent.

In March 2015, the MPUC voted to allow for full recovery, including a return, on approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used-and-useful for 2014. As a result of these determinations, ~~and assuming the other state commissions within the NSP System jurisdictions adopt the MPUC’s decisions,~~ Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of ~~2015. The~~2015, after which the remaining book value of the Monticello project ~~represents~~represented the present value of the estimated future cash ~~flows allowed for by the MPUC.~~

~~NSP-Minnesota – 2015 Transmission Cost Recovery (TCR) Rate Filing~~ — In October 2014, NSP-Minnesota submitted its 2015 TCR filing with the MPUC, requesting recovery of $65.8 million of 2015 transmission investment costs not included in electric base rates. The request for 2015 was reduced to approximately $63.8 million, which was approved by the MPUC in May 2015, subject to future adjustments replacing forecasted amounts with actual investment costs. The MPUC also set rates so that NSP-Minnesota will recover its remaining 2015 and forecasted 2016 revenue requirements through the end of 2016. New rates were implemented in July 2015, subject to true-up.

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

~~NSP-Minnesota – South Dakota 2015 Electric Rate Case~~—In June 2014, NSP-Minnesota filed a request with the SDPUC to increase electric rates by $15.6 million annually, or 8.0 percent, effective Jan. 1, 2015. Interim rates of $15.6 million, subject to refund, went into effect in January 2015.

In June 2015, the SDPUC approved a settlement agreement allowing a base rate increase of approximately $6.9 million, or 3.6 percent, and providing revisions to the existing Infrastructure rider, which will recover additional net revenue of $0.9 million. Combined, the overall revenue increase in base rates and the Infrastructure rider for 2015 is approximately $7.8 million, or 4.0 percent. New rates began in July 2015. In addition, there is a moratorium on base rate increases until Jan. 1, 2018.

The settlement also includes an earnings test with a sharing mechanism. If South Dakota’s weather normalized earnings exceed a certain level, NSP-Minnesota will refund 50 percent of the excess earnings to customers.flows.

NSP-Wisconsin

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

Wisconsin ~~2016~~2017 Electric and Gas Rate Case — ~~On May 29, 2015,~~In April 2016, NSP-Wisconsin filed a request with the PSCW ~~to increase rates~~ for ~~electric and natural gas service effective Jan. 1, 2016. NSP-Wisconsin requested~~ an ~~overall~~ increase in annual electric rates of ~~$27.4~~$17.4 million, or ~~3.9~~2.4 percent, and an increase in natural gas rates ~~of $5.9~~by $4.8 million, or ~~5.0 percent.~~3.9 percent, effective January 2017.

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The following table outlines the filed request:



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


^(a)	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 effectively increases NSP-Wisconsin’s requested electric rate increase to $26.9 million, or 3.8 percent.

The electric rate ~~filing~~request is ~~based on a 2016 forecast test year, a return on equity~~for the limited purpose of ~~10.2 percent, an equity ratio of 52.5 percent~~recovering increases in (1) generation and atransmission fixed charges and fuel and purchased power expenses related to the interchange agreement with NSP-Minnesota, and (2) costs associated with forecasted average ~~net investment~~ rate base of ~~approximately $1.2~~$1.188 billion in 2017.

The natural gas rate request is for the ~~electric utility~~limited purpose of recovering expenses related to the ongoing environmental remediation of a former manufactured gas plant (MGP) site and ~~$111.2 million~~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 ~~natural gas utility.~~earnings in excess of the authorized ROE would be refunded to customers.

Key dates in the procedural schedule are as follows:

Staff and ~~Intervenor Direct Testimony~~intervenor direct testimony — ~~Oct. 1, 2015;~~Aug. 12, 2016;

Rebuttal ~~Testimony~~testimony — ~~Oct. 19, 2015;~~Aug. 26, 2016;

~~Sur-Rebuttal Testimony~~Surrebuttal testimony — ~~Oct. 27, 2015;~~Sept. 2, 2016;

~~Technical~~ Hearing — ~~Oct. 29, 2015;~~Sept. 7, 2016;

Initial ~~Brief~~brief due — ~~Nov. 12, 2015;~~Sept. 21, 2016;

Reply ~~Brief~~brief due — ~~Nov. 19, 2015;~~Sept. 28, 2016; and

A final PSCW decision is anticipated in ~~December 2015.~~the fourth quarter of 2016 with final rates effective in January 2017.

~~Table of Contents~~

PSCo

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

~~PSCo – Colorado 2015 Multi-Year Gas Rate Case~~ — In March 2015, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas base rates by $40.5 million, or 3.5 percent, in 2015, with subsequent step increases of $7.6 million, or 0.7 percent, in 2016 and $18.1 million, or 1.5 percent, in 2017.

The request is based on a historic test year (HTY) ended June 30, 2014 adjusted for known and measurable expenses and capital additions for each of the subsequent periods in the multi-year plan and an equity ratio of 56 percent. The rate case requests an ROE of 10.1 percent for 2015 and 2016 and 10.3 percent for 2017, and a rate base of $1.26 billion for 2015, $1.31 billion for 2016 and $1.36 billion for 2017.

~~PSCo also proposed a stay-out provision, in which PSCo would not request implementation of new rates prior to January 2018, and implementation of an earnings test for 2016 through 2017.~~

In addition, PSCo requested an extension of its pipeline system integrity adjustment (PSIA) rider through 2020 to recover costs associated with its pipeline integrity efforts. The request to extend and modify the PSIA rider has an expected negative revenue impact of approximately $0.1 million in 2015 and would provide incremental revenue of $21.7 million for 2016 and $21.2 million for 2017. The following table summarizes the request:

(Millions of Dollars) 2015 2016 Step 2017 Step
Total base rate increase $ 40.5
$ 7.6
$ 18.1
Incremental PSIA rider revenues (0.1 ) 21.7
21.2
Total revenue impact $ 40.4
$ 29.3
$ 39.3

~~In June 2015, intervenors, including the CPUC Staff (Staff) and the Office of Consumer Counsel (OCC), filed testimony.~~

~~Staff recommended a base rate decrease of $14.7 million, based on an ROE of 9.0 percent and a 47.04 percent equity ratio;~~

~~OCC recommended a base rate increase of $5.8 million, based on an ROE of 9.0 percent and a 52.70 percent equity ratio;~~

~~A multi-year plan was opposed by both the Staff and OCC;~~

~~The Staff recommended deferring costs related to incremental property taxes and safety programs which are expected to be approximately $4.2 million in 2016 and $9.0 million in 2017; and~~

~~The Staff opposed PSCo’s proposed earnings test and the stay out provision.~~

~~Regarding the PSIA:~~

~~The Staff proposed extending the PSIA rider for three years;~~

~~The Staff recommended approximately $32.6 million of PSIA costs would be transferred to base rates, effective Jan. 1, 2016, in addition to the Staff’s proposed 2015 base rate adjustment; and~~

~~The OCC recommended the PSIA rider expire on June 30, 2016 and any costs be included in base rates through a step increase.~~

~~Table of Contents~~

~~The Staff and OCC’s 2015 base rate recommendations are summarized in the following table:~~

(Millions of Dollars) Staff OCC
PSCo’s filed 2015 base rate request $ 40.5
$ 40.5
ROE (12.8 ) (13.7 )
Capital structure and cost of debt (12.8 ) (4.8 )
Cherokee pipeline adjustment (11.2 ) 4.8
Move to 2014 historical test year (10.5 ) (16.4 )
O&M expenses (3.5 ) (2.7 )
Other, net (4.4 ) (1.9 )
Total adjustments $ (55.2 ) $ (34.7 )

Recommended (decrease) increase $ (14.7 ) $ 5.8

~~The Staff’s recommendation for the PSIA rider is as follows:~~

(Millions of Dollars) 2016 2017
PSCo’s filed incremental PSIA request $ 21.7
$ 21.2
Transfer PSIA O&M to base rates (24.1 ) (2.0 )
ROE and capital structure (8.2 ) (3.6 )
Transfer meter replacement program from base rates to PSIA 1.7
1.7
Total $ (8.9 ) $ 17.3

On July 20, 2015, PSCo filed rebuttal testimony, maintaining its request for a multi-year plan and requested ROEs and reflecting the most recent sales forecast. PSCo also accepts portions of the Staff’s position regarding the PSIA rider. PSCo’s rebuttal testimony, compared to its initial filed base rate and rider request are summarized as follows:

(Millions of Dollars) 2015 2016 Step 2017 Step
PSCo’s filed base rate request $ 40.5
$ 7.6
$ 18.1
Shift O&M expenses between PSIA and base rates —
7.0
6.4
Rebuttal corrections and adjustments —
—
(7.7 )
Total base rate request $ 40.5
$ 14.6
$ 16.8
Incremental PSIA rider revenues (0.1 ) 14.7
21.7
Total revenue impact from rebuttal $ 40.4
$ 29.3
$ 38.5

~~If PSCo’s revised request is accepted, PSIA revenue is projected to be $67.0 million in 2015, $81.7 million in 2016 and $103.4 million in 2017.~~

~~The next steps in the procedural schedule are as follows:~~

•~~Sur-Rebuttal Testimony — Aug. 3, 2015;~~

•~~Evidentiary Hearing — Aug. 18 - Aug. 31, 2015;~~

•~~Interim Rates (subject to refund) — Oct. 1, 2015; and~~

•~~Final CPUC Decision — No later than Jan. 20, 2016.~~

~~PSCo~~ —Annual Electric Earnings ~~Test~~Tests — As part of an annual earnings test, PSCo must share with customers a portion of any annual earnings that exceed PSCo’s authorized ROE threshold of 10 percent for 2012 through 2014. On April 30, 2015, PSCo filed a tariff for the 2014 earnings test with the CPUC proposing a refund obligation of $66.5 million to electric customers, which was approved by the CPUC in July 2015.

~~In February 2015, in the Colorado 2014 Electric Rate Case, the CPUC approved an annual earnings test, in which PSCo shares with customers’~~ earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. AsIn April 2016, PSCo filed the 2015 earnings test, proposing an electric customer refund obligation of $14.9 million, which was approved by the CPUC in July 2016. The proposed refund obligation related to the 2015 earnings test was accrued for as of June 30, ~~2015, PSCo has recognized management’s best~~2016. The current estimate of the ~~expected customer refund obligation for the 2015~~2016 earnings test, based on annual forecasted ~~information.~~

~~Table of Contents~~

~~Electric, Purchased Gas and Resource Adjustment Clauses~~

~~Demand Side Management (DSM) and the Demand Side Management Cost Adjustment (DSMCA)~~ — The CPUC approved higher savings goals and a lower financial incentive mechanism for PSCo’s electric DSM energy efficiency programs starting in 2015. Energy efficiency and DSM costs are recovered through a combination of the DSMCA riders and base rates. DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-upinformation, did not result in the following year. Savings goals were 384 gigawatt hours (GWh) in 2014 and are 400 GWh in 2015 with incentives awarded in the year following plan achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percentrecognition of ~~net economic benefits up to~~ a ~~maximum annual incentive~~liability as of ~~$30 million.~~June 30, 2016.

In October 2014, PSCo filed its 2015-2016 DSM plan, which proposes a 2015 DSM electric budget of $81.6 million, a 2015 DSM gas budget of $13.1 million, a 2016 DSM electric budget of $78.7 million and a 2016 DSM gas budget of $13.6 million. PSCo has reached an agreement with all parties resolving most of the contested issues in the proceeding. The remaining issues to be litigated primarily concern the avoided costs attributable to DSM measures. In July 2015, the administrative law judge (ALJ) approved the plan.

SPS

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

~~SPS –~~Appeal of the Texas 2015 Electric Rate Case Decision — 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.

Table of Contents

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.

The hearing in the appeal is scheduled for February 2017.

Texas 2015 Electric Rate Net Refund Case — Under an agreement in the Texas 2015 electric rate case, the final rates were retroactively applied to June 11, 2015. In June 2016, SPS filed an application to provide a net refund of approximately $1.25 million to reflect the difference in revenue SPS would have received for usage had SPS been charging the final rates approved by the PUCT from June 11, 2015 through Jan. 31, 2016. SPS has proposed to make the net refund over a six-month period beginning October 2016. The application is pending before the PUCT.

Texas 2016 Electric Rate Case — In ~~December 2014,~~February 2016, SPS filed a retail electric, non-fuel rate case in Texas ~~seeking~~with each of its Texas municipalities and the PUCT requesting an overall increase in annual base rate revenue of approximately ~~$64.8~~$71.9 million, or ~~6.7~~14.4 percent. The filing ~~was~~is based on a ~~HTY ending June 2014, adjusted for known and measurable changes,~~historic test year (HTY) ended Sept. 30, 2015, a requested ROE of 10.25 percent, an electric rate base of approximately ~~$1.6~~$1.7 billion, and an equity ratio of 53.97 percent. In ~~March 2015,~~April 2016, SPS revised its requested rate increase to ~~$58.9 million based on updated information.~~$68.6 million.

The following table summarizes the revised net request:



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

Key dates in the procedural schedule are as follows:

Intervenor direct testimony — Aug. 16, 2016;

PUCT Staff direct testimony — Aug. 23, 2016;

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

SPS’ rebuttal testimony — Sept. 9, 2016; and

Hearings — Sept. 27 - Oct. 7, 2016.

SPS ~~is seeking~~and various parties are having discussions regarding a ~~waiver~~potential settlement of the ~~PUCT post-test year adjustment rule which would allow for inclusion~~rate case. The final rates established at the end of ~~$392 million (SPS total company) additional capital investment for~~ the ~~period July 1, 2014 through Dec. 31, 2014.~~

~~In May 2015, several intervenors filed direct testimony in response~~case are expected to ~~SPS’ rate request, including the Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), and the PUCT Staff (Staff).~~

~~AXM recommended a rate decrease of $13.6 million, an ROE of 9.40 percent and an equity ratio of 53.97 percent.~~

~~The OPUC recommended a rate increase of $1.8 million, an ROE of 9.20 percent and an equity ratio of 52.38 percent.~~

~~The Staff recommended a rate decrease of $2.6 million, an ROE of 9.30 percent and an equity ratio of 53.97 percent.~~

~~In June 2015, SPS filed rebuttal testimony supporting a revised rate increase of approximately $42 million, or 4.4 percent.~~

SPS Rebuttal Testimony
(Millions of Dollars) AXM OPUC Staff
SPS’ revised rate request $ 58.9
$ 58.9
$ 58.9
$ 58.9
Investment for capital expenditures — post-test year adjustments (11.3 ) (23.8 ) (23.8 ) —
Lower ROE (10.9 ) (13.5 ) (12.1 ) —
Rate base adjustments (largely the removal of the prepaid pension asset) (6.2 ) (6.8 ) —
—
O&M expense adjustments (13.7 ) (11.0 ) (7.9 ) (1.6 )
Depreciation expense (13.3 ) —
—
—
Property taxes —
(1.2 ) (4.4 ) (1.8 )
Revenue adjustments (2.2 ) (0.2 ) —
—
Wholesale load reductions (13.2 ) —
(11.1 ) —
Southwest Power Pool (SPP) transmission expansion plan —
—
—
(7.3 )
Other, net (1.7 ) (0.6 ) (2.2 ) (1.8 )
Total recommendation $ (13.6 ) $ 1.8
$ (2.6 ) $ 46.4
Adjustment to move rate case expenses to a separate docket —
—
—
(4.3 )
Recommendation, excluding rate case expenses $ (13.6 ) $ 1.8
$ (2.6 ) $ 42.1

~~New rates will~~ be ~~made~~ effective retroactive to ~~June 11, 2015 as established by the PUCT. Hearings were completed in~~ July ~~2015.~~20, 2016. A PUCT decision is expected in the ~~fourth~~first quarter of ~~2015.~~2017.

~~Table of Contents~~

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

~~SPS –~~ New Mexico 2015 Electric Rate Case —In ~~June~~October 2015, SPS filed an electric rate case with the NMPRC ~~for~~seeking an increase in non-fuel base rates of ~~$31.5 million and~~$45.4 million. The proposed increase would be offset by a decrease in base fuel ~~decrease~~revenue of ~~$30.1~~approximately $21.1 million. The rate filing ~~was~~is based on a ~~2016 forecast test year (FTY),~~June 30, 2015 HTY adjusted for known and measurable changes, a requested ~~return on equity~~ROE of 10.25 percent, ~~a jurisdictional~~an electric rate base of ~~$777.9~~approximately $734 million and an equity ratio of 53.97 percent.

In ~~June 2015, SPS’ rate case application was dismissed by~~May 2016, SPS, the ~~NMPRC. The~~ NMPRC ~~determined~~Staff and all other parties filed a unanimous black-box stipulation that ~~the filing did not comply with its new interpretation of the statute regarding FTY periods and the corresponding timing of a rate case submission in relation to the FTY used~~resolves all issues in the case. ~~This new interpretation occurred during~~Under the ~~recent Public Service Company~~stipulation, SPS will implement a non-fuel base rate increase of ~~New Mexico~~$23.5 million and a decrease in base fuel revenue of approximately $21.1 million. The decrease in base fuel revenue will be reflected in adjustments collected through the fuel and purchased power cost adjustment clause. The stipulation places no restriction on when SPS may file its next base rate case.

In July ~~SPS filed an appeal with~~2016, the ~~New Mexico Supreme Court. In addition, SPS plans~~hearing examiner issued a recommendation that the NMPRC approve the stipulation. The stipulation is subject to ~~file~~approval by the NMPRC and a ~~rate case later this year.~~decision on the settlement and implementation of final rates is expected in fall of 2016.

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Pending ~~and Recently Concluded~~ Regulatory Proceedings — FERC

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

In ~~June 2014,~~December 2015, an ALJ initial decision recommended the FERC approve a ROE of 10.32 percent. A FERC order is expected to be issued an order adopting a new ROE methodology, which requires electric utilities to use a two-step discounted cash flow analysis that incorporates both short-term and long-term growth projections to estimate the cost of equity.in late 2016 or in 2017.

In February 2015, a second complaint was filed seeking to reduce the MISO region ROE from 12.38 percent to 8.67 percent, prior to any adder. The FERC set the ~~ROE~~second complaint ~~against the MISO TOs~~ for ~~settlement~~hearings, and ~~hearing procedures. The FERC directed parties to apply the new ROE methodology, but denied the complaints related to equity capital structures and ROE adders. The FERC~~ established a ~~Nov. 12, 2013~~ refund effective ~~date.~~date of Feb. 12, 2015. The ~~settlement procedures were unsuccessful. In January 2015,~~MPUC, the ~~ROE complaint was set for full hearing procedures.~~

~~The complainants~~North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission and ~~intervenors filed testimony~~the DOC joined a joint complainant/intervenor initial brief recommending an ROE ~~between 8.67~~of either 8.82 percent ~~and 9.54~~or 8.81 percent. ~~The~~ FERC staff recommended ana ROE of ~~8.68~~8.78 percent. The MISO TOs recommended ana ROE ~~not less than 10.8~~of 10.92 percent. ~~A hearing is scheduled for August 2015, with~~On June 30, 2016, the ALJ issued an ~~ALJ~~ initial decision ~~to be issued by November 2015 and~~recommending a ROE of 9.7 percent, the midpoint of the upper half of the discounted cash flow (DCF) range, with refunds for the 15 month period beginning Feb.12, 2015. A FERC ~~order issued no earlier than 2016.~~decision is expected in 2017.

~~In November 2014, certain MISO TOs filed a request for~~ FERC ~~approval~~approved of a 50 basis point ROE adder for RTO membership, ~~ROE adder, with collection deferred until resolution of the ROE complaint. In January~~effective Jan. 6, 2015, ~~the FERC approved the ROE adder,~~ subject to the outcome of the ROE complaint. ~~The~~Under FERC policy, the total ROE including the RTO membership adder ~~may not~~cannot exceed the top of the ~~discounted cash flow range under the new ROE methodology.~~

In February 2015, an intervenor in the November 2013 ROE complaint filed a second complaint proposing to reduce the MISO region ROE to 8.67 percent, prior to any 50 basis point RTO adder. In June 2015, the FERC set the second ROE complaint for a hearing process, establishing a Feb. 12, 2015 refund effective date. An ALJ initial decision is expected in June 2016 with a FERC decision in late 2016 or in 2017. The FERC decision would continue the ROE refund obligation initiated under the November 2013 complaint through May 2016. On July 20, 2015, the MISO TOs sought rehearing of the FERC decision to allow back-to-back complaints involving the same issue with consecutive refund periods, arguing this ruling is contrary to the governing statute. FERC action on the rehearing request is pending.DCF range.

NSP-Minnesota has recorded a current liability representing the ~~current~~ best estimate of a refund obligation associated with the new ROE, including the RTO membership adder, as of June 30, ~~2015.~~2016. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $7$8 million and $9$10 million, annually, for the NSP System.

~~SPS – Wholesale Rate ROE Complaints~~Southwest Power Pool, Inc. (SPP) Open Access Transmission Tariff (OATT) Upgrade Costs — ~~In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread), a wholesale cooperative customer, filed a rate complaint alleging that~~Under the ~~base ROE included~~SPP OATT, costs of participant-funded, or “sponsored,” transmission upgrades may be recovered, in part, from other SPP customers whose transmission service depends on capacity enabled by the ~~SPS production formula rate for Golden Spread of 10.25 percent, and the SPS transmission base formula rate ROE of 10.77 percent, are unjust and unreasonable, and asking that the ROEs be reduced~~upgrade. The SPP OATT has allowed SPP to 9.15 percent and 9.65 percent, respectively, effective April 20, 2012. In July 2013, Golden Spread filed a second complaint, again asking that the ROE in the SPS production formula rate for Golden Spread and transmission formula rates be reducedcollect charges since 2008, but to 9.15 and 9.65 percent, respectively, effective July 19, 2013. In June 2014, the FERC issued orders consolidating the Golden Spread ROE complaints and setting the complaints for settlement judge or hearing procedures.

~~Table of Contents~~

A third rate complaint was filed in October 2014 by Golden Spread, certain New Mexico cooperatives and the West Texas Municipal Power Agency, requesting that the ROE in certain SPS production formula rates for Golden Spread and the New Mexico cooperatives and transmission formula rates be reduced, this timedate SPP has not charged its customers any amounts attributable to 8.61 percent and 9.11 percent, respectively, effective Oct. 20, 2014. In January 2015, the FERC issued an order setting the third complaint for hearing procedures and granting the complainants’ requested refund effective date. The FERC established effective dates for refunds of April 20, 2012 (first refund period), July 19, 2013 (second refund period) and Oct. 20, 2014 (third refund period), respectively.these upgrades.

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 ~~sought~~is considering whether to seek clarification or rehearing of the FERC ~~decisions~~order. SPP has indicated it anticipates completing its process and invoicing customers during the fourth quarter of 2016. SPS estimates the charges to ~~allow back-to-back complaints involving the same issue with consecutive 15 month refund periods, asserting this ruling is contrary~~be $5 million to the governing statute. On May 12, 2015, FERC denied the rehearing request as it pertained to the first two rate complaints. In July 2015, SPS filed an appeal to the D.C. Circuit Court of Appeals of the FERC orders in the first two rate complaints allowing the sequential complaints and consecutive 15 month refund periods. The D.C. Circuit Court has not established a procedural schedule. FERC action on the similar SPS rehearing request related to the third complaint is pending.

~~In the first half of 2015, Golden Spread, SPS and FERC staff filed their initial testimonies recommending the following ROEs:~~

Refund Period Production ROE
Transmission ROE ^(a)
Golden Spread ^(b)
1 8.78 % 9.28 %
2 8.51
9.01
3 8.45
8.95
SPS 1 10.25
10.39
2 10.25
11.20
3
^(c)
10.40
11.20
FERC Staff 1 8.97
9.47
2 8.64
9.14
3 8.53
9.03


^(a)	~~Includes a SPP RTO membership adder up to 50 basis points.~~


^(b)	For the third refund period, the recommended production and transmission ROEs are supported by Golden Spread, certain New Mexico cooperatives and the West Texas Municipal Power Agency (transmission ROE only).


^(c)	~~In addition to the recommended ROEs,SPS also filed testimony recommending the ROEs remain unchanged.~~

~~Hearings scheduled for July 2015 for the first two rate complaints were canceled and the parties agreed to file briefs~~$10 million, based on ~~pre-filed testimony. An initial ALJ decision on the first two complaints is expected to~~preliminary information. SPS anticipates these costs would be issued by Nov. 25, 2015, and a final FERC order to be issued no earlier than 2016. A hearing for the third rate complaint is scheduled for Oct. 2015, with an ALJ initial decision expected in January 2016 and a final FERC order no earlier than later in 2016.

SPS recorded a current liability representing the current best estimate of a refund obligation associated with potential ROE adjustments as of June 30, 2015, and is reducing transmission and production revenues, net of expense, between $4 million and $6 million annually.recoverable through regulatory mechanisms.

~~SPS – 2004 FERC Complaint Case Orders~~—In August 2013, the FERC issued an order related to a 2004 complaint case brought by Golden Spread and Public Service Company of New Mexico (PNM) and an Order on Initial Decision in a subsequent 2006 production rate case filed by SPS.

The original complaint included two key components: 1) PNM’s claim regarding inappropriate allocation of fuel costs and 2) a base rate complaint, including the appropriate demand-related cost allocator. The FERC previously determined that the allocation of fuel costs and the demand-related cost allocator utilized by SPS was appropriate.

In the August 2013 Orders, the FERC clarified its previous ruling on the allocation of fuel costs and reaffirmed that the refunds in question should only apply to firm requirements customers and not PNM’s contractual load. The FERC also reversed its prior demand-related cost allocator decision. The FERC stated that it had erred in its initial analysis and concluded that the SPS system was a 3 coincident peak (CP) rather than a 12 CP system.

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In September 2013, SPS filed a request for rehearing of the FERC ruling on the CP allocation and refund decisions. SPS asserted that the FERC applied an improper burden of proof and that precedent did not support retroactive refunds. PNM also requested rehearing of the FERC decision not to reverse its prior ruling. In October 2013, the FERC issued orders further considering the requests for rehearing, which are currently pending. As of Dec. 31, 2014, SPS had accrued $50.4 million related to the August 2013 Orders and an additional $1.5 million of principal and interest has been accrued during 2015.

~~SPS – 2015 Production Formula Rate Change Filing~~—In January 2015, SPS filed to revise the production formula rates for six of its wholesale customers, including Golden Spread, certain New Mexico cooperatives and West Texas Municipal Power Agency, effective Feb. 1, 2015. The filing proposes several modifications, including a reduction in wholesale depreciation rates and the use of a 12 CP demand-related cost allocator for all wholesale customers. In March 2015, the FERC accepted this filing, effective July 1, 2015, subject to refund and settlement judge or hearing procedures. The parties remain engaged in settlement judge procedures. Effective June 1, 2015, the Golden Spread contract demand quantity subject to the formula rate change declined from 500 MW to 300 MW.


6.	Commitments and Contingencies

Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 5, 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, ~~2014~~2015, and in Notes 5 and 6 to the consolidated financial statements included in Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, ~~2015,~~2016, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to Xcel Energy’s financial position.

Purchased Power Agreements (PPAs)

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

The Xcel Energy utility subsidiaries had approximately 3,467 MW and 3,698 MW of ~~capacity~~capacity under long-term PPAs as of June 30, ~~2015~~2016 and Dec. 31, ~~2014,~~2015, with entities that have been determined to be variable interest entities. Xcel Energy has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2033.

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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 limit the exposure to a maximum amount stated in the guarantees and bond indemnities. As of June 30, ~~2015~~2016 and Dec. 31, ~~2014,~~2015, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.

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


(Millions of Dollars)	June 30, 2015		Dec. 31, 2014		June 30, 2016		Dec. 31, 2015
Guarantees issued and outstanding	$	13.2	$	13.9	$	15.9	$	12.5
Current exposure under these guarantees	0.1		0.2		0.1		0.1
Bonds with indemnity protection	41.9		31.4		43.0		41.3

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Other Indemnification Agreements

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

Environmental Contingencies

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

~~The U.S.~~In 2010, the United States Environmental Protection Agency (EPA) issued its Record of Decision (ROD) ~~in 2010, which describes the~~, including their preferred remedy ~~the EPA has selected~~ for the ~~cleanup of the Ashland site. For the~~ Sediments ~~at the Ashland Site, the ROD preferred remedy~~which is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). ~~The ROD also identifies the possibility of a~~A wet conventional dredging only remedy ~~for the Sediments~~ (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot ~~study.~~study, is another potential remedy.

In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the Ashland site. As a result of settlement negotiations with NSP-Wisconsin, the EPA agreed to segment the Ashland site into separate areas. The first area (Phase I Project Area) includes soil and groundwater in Kreher Park and the Upper Bluff. The second area includes the Sediments.

~~In October~~ 2012, under a settlement among the EPA, the Wisconsin Department of Natural Resources, the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin was approved by the U.S. District Court for the Western District of Wisconsin. This settlement resolves claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area. Under the terms of the settlement,agreement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area ~~but does not admit any liability with respect to~~(which includes the ~~Ashland site. Fieldwork to address~~Upper Bluff and Kreher Park areas of the ~~Phase I Project Area at the Ashland site began at the end of 2012 and continues. Demolition activities occurred at the Ashland site in 2013. Soil, including~~Site). The excavation and containment remedies are complete, and a long-term groundwater pump and treatment ~~as well as containment wall remedies were completed in early 2015. A preliminary~~program is now underway. The final design ~~for the groundwater remedy~~ was ~~also submitted to~~approved by the EPA in ~~April 2014 and preliminary activities, including the installation of ground wells, have commenced at the site. Construction on the groundwater treatment plant is anticipated to commence in fall~~ 2015. The current cost estimate for the cleanup of the Phase I Project Area is approximately ~~$57~~$71.4 million, of which approximately ~~$35~~$51.8 million has already been spent. The settlement also resolves claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments.

Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay for or perform the cleanup of the Sediments and ~~what~~which remedy will be ~~implemented at the site to address the Sediments. It is NSP-Wisconsin’s view that the Hybrid Remedy is not safe or feasible to implement.~~implemented. The EPA’s ROD ~~for the Ashland site~~ includes estimates that the cost of the Hybrid Remedy is between $63 million and $77 million, with a potential deviation in such estimated costs of up to 50 percent higher toor 30 percent lower. NSP-Wisconsin believes the Hybrid Remedy is not safe or feasible to implement. In ~~November 2013,~~2015, NSP-Wisconsin ~~submitted~~constructed a ~~revised Wet Dredge~~breakwater at the site to serve as wave attenuation and containment for a wet dredge pilot study ~~work plan proposal to~~and full scale sediment remedy at the ~~EPA. In May 2014, NSP-Wisconsin entered into a final administrative order on consent~~site. Equipment mobilization for the ~~Wet Dredge~~wet dredge pilot study ~~with~~commenced in April 2016. The pilot study is expected to conclude in late summer of 2016. The EPA will then determine whether NSP-Wisconsin can perform extended pilot work into early fall of 2016 and whether a full scale wet dredge remedy of the ~~EPA.~~Sediments may be performed beginning as early as 2017.

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In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site. Trial for this matter took place in May 2015. A judicial decision is expected in the third quarter of 2015. A final settlement has been reached between NSP-Wisconsin, along with the EPA, and two of the PRPs, Wisconsin Central Ltd. and Soo Line Railroad Co. (collectively, the “Railroad PRPs”) resolving claims relating to the Railroad PRPs’ share of the costs of cleanup at the Ashland site. NSP-Wisconsin also has entered a second private party settlement agreement with LE Myers Co. Under the agreements, the Railroad PRPs contributed $10.5 million and LE Myers Co. contributed $5.4 million to the costs of the cleanup at the Ashland site. The agreements for the Railroad PRPs and LE Myers Co. were approved by the U.S. District Court for the Western District of Wisconsin in 2015 and payment has been received. As discussed below, existing PSCW policy requires that any payments received from PRPs be used to reduce the amount of the cleanup costs ultimately recovered from customers. Two additional PRPs remain in the case.

At June 30, ~~2015~~2016 and Dec. 31, ~~2014,~~2015, NSP-Wisconsin had recorded a liability of ~~$108.5~~$95.0 million and ~~$107.6~~$94.4 million, respectively, for the ~~Ashland site~~Site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which ~~$23.2~~$18.7 million and ~~$28.9~~$17.0 million, respectively, ~~was~~were considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the ~~time frame over which the amounts may be paid~~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 ~~ultimate~~ remediation cost of the entire site. Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, potential contributions by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.

NSP-Wisconsin has deferred the estimated site remediation costs as a regulatory ~~asset, based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers.~~asset. The PSCW has consistently authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the ~~Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities. Under the established PSCW policy, once deferred MGP remediation costs are determined by~~Site. In a December 2012 decision, the PSCW agreed to ~~be prudent, utilities are allowed~~allow NSP-Wisconsin to ~~recover those deferred~~pre-collect certain costs, in natural gas rates, typically over a four- to six-year amortization period. The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.

The PSCW reviewed the existing MGP cost recovery policy as it applied to the Ashland site in the context of NSP-Wisconsin’s 2013 general rate case. In December 2012, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site and granted an exception to its existing policy at the request of NSP-Wisconsin. The elements of this exception include: (1) approval to begin recovery of estimated Phase 1 Project costs beginning on Jan. 1, 2013; (2) approval to amortize ~~these estimated~~ costs over a ten-year ~~period;~~period, and ~~(3) approval~~ to apply a three percent carrying cost to the unamortized regulatory asset. In April 2016, NSP-Wisconsin filed a ~~2014~~limited natural gas rate case ~~decision,~~for recovering additional expenses associated with remediating the PSCW continued the cost recovery treatment with respect to the 2013 and 2014 cleanup costs for the Phase I Project Area and allowed NSP-Wisconsin to increase its 2014 amortization expense related to the cleanup by an additional $1.1 million to offset the need for a rate decrease for the natural gas utility. Cost recovery will continue at the level set in the 2014 rate case though 2015. In May 2015, NSP-Wisconsin filed its 2016 rate case, in which it requested an increase toSite. If approved, the annual recovery ~~for~~of MGP clean-up costs would increase from ~~$4.7~~$7.6 million in 2016 to ~~$7.6 million. A decision is anticipated~~$12.4 million in ~~late 2015.~~2017.

Fargo, N.D. MGP Site — In May 2015, ~~in connection with a city water main replacement and street improvement project in Fargo, N.D.,~~ underground pipes, tars and impacted soils were discovered in Fargo, N.D., which may be related to a former MGP site operated by NSP-Minnesota or a prior ~~company, were discovered. After initial reports and discussions with the City of Fargo and the North Dakota Department of Health,~~company. NSP-Minnesota has removed the impacted soils and other materials from the project area. ~~At this time, NSP-Minnesota’s~~NSP-Minnesota is undertaking further investigation of the location of the historic MGP site ~~is considered preliminary as information is still being gathered.~~and nearby properties. In October 2015, NSP-Minnesota initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota agreed to the parties’ request for a stay of the litigation until November 2016 to allow NSP-Minnesota time to further investigate site conditions.

As of June 30, 2016 and Dec. 31, 2015, NSP-Minnesota had recorded a liability of ~~$2.1~~$1.6 million and $2.7 million, respectively, related to further investigation and additional planned activities. Uncertainties include the nature and cost of the additional remediation efforts that may be necessary, the ability to recover costs from insurance carriers and the potential for contributions from entities that may be identified as PRPs. Therefore, the total cost of remediation, NSP-Minnesota’s potential liability and amounts allocable to the North Dakota and Minnesota jurisdictions related to the site cannot currently be reasonably estimated. In ~~July~~December 2015, ~~NSP-Minnesota filed a~~the NDPSC approved NSP-Minnesota’s request ~~with the North Dakota Public Service Commission (NDPSC) for approval~~ to ~~initially~~ defer the portion of investigation and response costs allocable to the North Dakota jurisdiction.

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Environmental Requirements

Water and Waste

~~Federal Clean Water Act (CWA) Waters~~Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of ~~the United States Rule~~ —solid waste. In ~~June~~April 2015, the EPA ~~and the U.S. Army Corps of Engineers~~ published a final rule ~~that significantly expands~~regulating the ~~types~~management and disposal of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.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,coal combustion byproducts (coal ash) as well as increasing project costs and expanding permitting and reporting requirements. The rule will go into effect beginning in August 2015. Xcel Energy does not anticipate the costs of compliance witha nonhazardous waste. Under the final rule, Xcel Energy’s costs to manage and dispose of coal ash has not significantly increased.

In 2015, industry and environmental non-governmental organizations sought judicial review of the final rule. In June 2016, the D.C Circuit issued an order remanding and vacating certain elements of the rule as a result of partial settlements with these parties. Oral arguments are expected to be heard in the second half of 2016 and a final decision is anticipated in early 2017. Until a final decision is reached in the case, it is uncertain whether the litigation or partial settlements will have ~~a material~~any significant impact on ~~the~~ results of operations, financial position or cash ~~flows.~~flows on Xcel Energy.

Air

~~Cross-State Air Pollution Rule (CSAPR)~~ ~~— CSAPR addresses long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO~~₂~~) and nitrous oxide (NOx) from utilities in the eastern half of the United States using an emissions trading program. For Xcel Energy, the rule applies in Minnesota, Wisconsin and Texas.~~

In August 2012, the United States District Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act (CAA) and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that were considered on remand. In July 2015, the D.C. Circuit issued an opinion which found the reduction budgets exceed what is necessary for Texas to reduce its impact on downwind states that do not meet ambient air quality standards. The D.C. Circuit remanded the matter to the EPA to reconsider the emission budgets. While the EPA reconsiders emission budgets, the D.C. Circuit left CSAPR in effect.

In October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPR by imposing its 2012 compliance obligations starting in January 2015. While the litigation continues, the EPA is administering the CSAPR in 2015.

Multiple changes to the SPS system since 2011 will substantially reduce estimated costs of complying with the CSAPR. These include the addition of 700 MW of wind power, the construction of Jones Units 3 and 4, reduced wholesale load, new PPAs, installation of NOx combustion controls on Tolk Units 1 and 2 and completion of certain transmission projects. As a result, SPS estimates compliance with the CSAPR in 2015 will cost approximately $7 million or less.

~~NSP-Minnesota can operate within its CSAPR emission allowance allocations. NSP-Wisconsin can operate within its CSAPR emission allowance allocation for SO~~₂. NSP-Wisconsin is complying with the CSAPR for NOx in 2015 through operational changes or allowance purchases. CSAPR compliance in 2015 is not having a material impact on the results of operations, financial position or cash flows.

~~Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule —~~ The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. By April 2015, the MATS compliance deadline, Xcel Energy had met the EGU MATS rule through a combination of emission control projects and controls required by other programs preceding MATS, such as regional haze and state mercury regulations. Xcel Energy also retired two coal units at the Black Dog plant and ceased use of coal at Bay Front Unit 5. In addition, mercury controls were installed in SPS’ Tolk and Harrington plants for a capital cost of $8 million. On June 29, 2015, the U.S. Supreme Court found that the EPA acted unreasonably by not considering the cost to regulate mercury and other hazardous air pollutants. The D.C. Circuit, on remand, will decide whether to leave MATS in effect while the EPA considers such costs in making a new determination. Xcel Energy believes EGU MATS costs will be recoverable through regulatory mechanisms and does not anticipate a material impact on the results of operations, financial position or cash flows.

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in ~~certain~~ national parks and wilderness areas. ~~In its first~~Under BART, regional haze ~~state implementation plan (SIP), Colorado, Minnesota and Texas identified the Xcel Energy~~plans identify facilities that will have to reduce SOsulfur dioxide (SO₂), ~~NOx~~nitrogen oxide (NOx) and PMparticulate matter (PM) emissions ~~under BART~~ and set ~~emissions~~emission limits for those facilities. BART requirements can also be met through participation in interstate emission trading programs such as the Clean Air Interstate Rule (CAIR) and its successor, Cross-State Air Pollution Rule (CSAPR).

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~~PSCo~~

In 2011, the Colorado Air Quality Control Commission approved a SIP (the Colorado SIP) that included the CACJA emission reduction plan as satisfying regional haze requirements for the facilities included in the CACJA plan. In addition, the Colorado SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the Colorado SIP in 2012. Installation of the emission controls at Hayden Unit 1 is scheduled for 2015 and Hayden Unit 2 is scheduled for 2016 at an estimated combined cost of $82.4 million. PSCo anticipates these costs will be fully recoverable in rates.

~~In March 2013, WildEarth Guardians petitioned the U.S. Court of Appeals for the 10~~^th Circuit to review the EPA’s decision approving the Colorado SIP. WildEarth Guardians has challenged the BART determination made for Comanche Units 1 and 2. In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent or that selective catalytic reduction (SCR) be added to the units. In September 2014, the EPA filed a request with the Court to remand the case to the EPA for additional explanation of the EPA’s decision approving the BART determination for Comanche Units 1 and 2. In October 2014, the Court granted the EPA’s request and vacated the current briefing schedule. In May 2015, the EPA published its final rule which re-affirmed the approval of the State of Colorado’s BART determination for Comanche Units 1 and 2. The determination found that the controls currently installed on the units for NOx are BART. In July 2015, WildEarth Guardians filed a petition for review of the EPA's May 2015 final rule. The 10^th ~~Circuit will now resume litigation and a decision is anticipated in 2016.~~

In 2010, two environmental groups petitioned the U.S. Department of the Interior (DOI) to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. The following PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege the Colorado BART rule is inadequate to satisfy the CAA mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when the DOI will rule on the petition.

~~NSP-Minnesota~~

In 2009, the Minnesota Pollution Control Agency (MPCA) approved a SIP (the Minnesota SIP) and submitted it to the EPA for approval. The MPCA’s source-specific BART limits for Sherco Units 1 and 2 require combustion controls for NOx and scrubber upgrades for SO₂. The MPCA concluded SCRs should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs. The combustion controls were installed first and the scrubber upgrades were completed in December 2014, at a cost of $46.9 million. NSP-Minnesota anticipates these costs will be fully recoverable in rates.

The MPCA supplemented its Minnesota SIP, determining that CSAPR meets BART requirements, but also implementing its source-specific BART determination for Sherco Units 1 and 2 from the 2009 Minnesota SIP. In June 2012, the EPA approved the Minnesota SIP for EGUs and also approved the source-specific emission limits for Sherco Units 1 and 2 as strengthening the Minnesota SIP, but avoided characterizing them as BART limits.

In August 2012, the National Parks Conservation Association, Sierra Club, Voyageurs National Park Association, Friends of the Boundary Waters Wilderness, Minnesota Center for Environmental Advocacy and Fresh Energy appealed the EPA’s approval of the Minnesota SIP to the U.S. Court of Appeals for the Eighth Circuit (Eighth Circuit). NSP-Minnesota and other regulated parties were denied intervention. In June 2013, the Eighth Circuit ordered this case to be held in abeyance until the U.S. Supreme Court decided the CSAPR case. If this litigation ultimately results in further EPA proceedings concerning the Minnesota SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2.

~~SPS~~

~~Harrington Units 1 and 2 are potentially subject to BART.~~ Texas developed a ~~SIP (the Texas SIP)~~state implementation plan (SIP) that finds the CAIR equal to BART for ~~EGUs.~~electric generating units (EGUs). As a result, no additional controls beyond CAIR compliance would be required. In ~~May 2012, the EPA deferred its review of the Texas SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs. In~~ December 2014, the EPA proposed to approve the BART portion of the ~~Texas~~ SIP, with the exception that the EPA would substitute the 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 United States Court of Appeals for the District of Columbia Circuit’s (D.C. Circuit) remand of the Texas SO₂emission budgets. In March 2016, the EPA requested information under the Clean Air Act (CAA) 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. The EPA ~~currently plans~~is expected to issue ~~its final~~a proposed rule in December ~~2015.~~

2016. In ~~May 2014,~~June 2016, the EPA issued a ~~request for information under~~memorandum which allows Texas to voluntarily adopt the ~~CAA related to~~CSAPR emission budgets limiting annual SO₂ ~~control equipment at Tolk Units 1~~ and 2. 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 Texas Commission on Environmental Quality (TCEQ) intends to utilize this option.

In December 2014, the EPA proposed to disapprove the reasonable progress portions of the ~~Texas~~ SIP and instead adopt a ~~Federal Implementation Plan. The~~federal implementation plan (FIP). In January 2016, the EPA ~~proposed to require dry scrubbers on both Tolk units to reduce~~adopted a final rule establishing a FIP for the state of Texas. As part of this final rule, the EPA imposed SO₂ ~~emissions to help achieve reasonable progress goals for Texas and Oklahoma national parks and wilderness areas. As proposed,~~emission limitations that reflect the installation of dry scrubbers ~~would need to~~on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be ~~installed~~approximately $600 million. In March 2016, SPS appealed the EPA’s decision and ~~operating within five years~~asked for a stay of the ~~EPA’s~~ final ~~action, currently expected in December 2015. Whether dry scrubbers are required~~rule while it is ~~dependent on~~being reviewed. In July 2016, the ~~EPA’s~~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 the appropriate venue for this case. In addition, SPS filed a petition with the EPA requesting reconsideration of the final ~~decision. If required, they would cost approximately $600 million, with an annual operating cost of approximately $10.4 million. Xcel Energy~~rule. SPS believes these costs would be recoverable through regulatory mechanisms if required, and therefore does not expect a material impact on ~~results of operations, financial position or cash flows.~~

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~~Reasonably Attributable Visibility Impairment (RAVI)~~ — RAVI is intended to address observable impairment from a specific source such as distinct, identifiable plumes from a source’s stack to a national park. In 2009, the DOI certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2. The EPA is required to determine whether there is RAVI-type impairment in these parks and identify the potential source of the impairment. If the EPA finds that Sherco Units 1 and 2 cause or contribute to RAVI in the national parks, the EPA would then evaluate whether the level of controls required by the MPCA is appropriate. The EPA has stated it plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program.

In December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota (Minnesota District Court) by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club. The lawsuit alleges the EPA has failed to perform a nondiscretionary duty to determine BART for Sherco Units 1 and 2 under the RAVI program. The EPA filed an answer denying the allegations. The District Court denied NSP-Minnesota’s motion to intervene in July 2013. NSP-Minnesota appealed this decision to the Eighth Circuit, which on July 23, 2014, reversed the District Court and found that NSP-Minnesota has standing and a right to intervene.

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

As required by the CAA, the EPA published notice of the proposed settlement in the Federal Register. The EPA reviewed the public comments in July 2015 and notified the Minnesota District Court that the settlement agreement is final. The EPA has seven months to recommend and adopt a rule which will set the agreed-upon SO₂~~emissions. Xcel Energy does not anticipate the costs of compliance with the proposed settlement will have a material impact on the~~ results of operations, financial position or cash flows.

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

~~Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and under a consent decree the~~The EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant and SPS’ Tolk and Harrington plants. The Pawnee plant recently installed an SO₂ scrubber and the Tolk and Harrington Plants utilize low sulfur coal to reduce SO₂ emissions. In 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 that the area near the Pawnee plant will be able to show compliance with the NAAQS through air dispersion modeling performed by the Colorado Department of Public Health and ~~Environment along with the Texas Commission on Environmental Quality (TCEQ) are expected to make recommendations for nonattainment areas to the EPA in September 2015 with a decision by summer 2016.~~ Environment.

If an area is designated nonattainment in 2020, the respective states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan, ~~for the respective areas~~ which would be due ~~in 18 months,~~by 2022, designed to achieve the NAAQS ~~within five years.~~by 2025. The TCEQ could require additional SO₂ controls ~~on one or more~~at Harrington as part of ~~the units at Tolk and Harrington. It is anticipated the~~such a plan. The areas near the remaining Xcel Energy power plants ~~would~~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 ~~of this ruling~~ until the designation of nonattainment areas is made and any required state plans are developed. Xcel Energy believes that, should SO₂ control systems be required for a plant, compliance costs will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.

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Legal Contingencies

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

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Employment, Tort and Commercial Litigation

Pacific Northwest FERC Refund Proceeding — ~~In July 2001,~~A complaint with the FERC ~~ordered a preliminary hearing to determine whether there~~posed that sales made in the Pacific Northwest in 2000 and 2001 through bilateral contracts were unjust and unreasonable ~~charges for spot market bilateral sales in~~under the Pacific Northwest for December 2000 through June 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the resultFederal Power Act. The City of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling, the FERC has allowed the parties to request additional evidence. Parties have claimed that the total amount of transactions with PSCo subject to refund isSeattle (the City) alleges between $34 million. to $50 million in sales with PSCo is subject to refund. In ~~June~~ 2003, the FERC ~~issued an order terminating~~terminated the proceeding, ~~without ordering further proceedings. Certain purchasers filed appeals of~~although it was later remanded back to the ~~FERC’s orders~~FERC in ~~this proceeding with~~2007 by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).

In ~~an order issued in August 2007, the Ninth Circuit remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges~~May 2015, in the ~~California organized markets. The Ninth Circuit denied a petition for rehearing in April 2009, and the mandate was issued.~~

~~The FERC issued an order on~~ remand ~~establishing principles for the review~~ proceeding, ~~in October 2011. The City of Seattle filed a petition for review with the Court of Appeals for the Ninth Circuit seeking review of FERC’s order on remand.~~

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

~~In April 2013,~~ the FERC issued an order ~~on rehearing. The FERC confirmed that~~rejecting the City of Seattle would be able to attempt to obtain refunds back from January 2000, but reaffirmed the transaction-specific standard that the City of Seattle and other complainants would have to comply with to obtain refunds. In addition, the FERC rejected the imposition of any market-wide remedies. Although the FERC order on rehearing established the period for which the City of Seattle could seek refunds as January 2000 through June 2001, it is unclear whatCity’s claim the City of Seattle has against PSCo prior to June 2000. In the proceeding, the City of Seattle does not allege specific misconduct or tariff violations by PSCo but instead asserts generally that the rates charged by PSCo and other sellers were excessive.

A hearing in this case was held before a FERC ALJ and concluded in October 2013. On March 28, 2014, the FERC ALJ issued an initial decision which rejected all of the City of Seattle’s claims against PSCo and other respondents. With respect to the period Jan. 1, 2000 through Dec. 24, 2000, the FERC ALJ rejected the City of Seattle’s assertion that any of the sales made ~~to the City of Seattle~~ resulted in an excessive burden ~~to the City of Seattle, the applicable legal standard for the City of Seattle’s challenges during this period. With respect to the period Dec. 25, 2000 through June 20, 2001, the FERC ALJ~~and concluded that the City ~~of Seattle had~~ failed to establish a causal link between any contracts and any claimed unlawful market ~~activity,~~activity. In February 2016, the ~~standard required by the FERC in its remand order. The~~ City ~~of Seattle contested the FERC ALJ’s initial~~appealed this decision ~~by filing a brief on exceptions~~ to the ~~FERC.~~Ninth Circuit. This ~~matter~~appeal is ~~now~~ pending ~~a decision~~review by ~~the FERC.~~

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In addition, on Feb. 17, 2015, the U.S. Court of Appeals of the Ninth Circuit directed parties to the pending FERC proceeding to submit briefs addressing, among other issues, the petition for review filed by the City of Seattle seeking review of FERC’s order on remand. Parties are directed to address whether FERC’s order properly established the scope for the hearing that concluded in October 2013. Respondent-intervenors, including PSCo jointly with others, submitted briefs on May 8, 2015. Oral argument was held on June 16, 2015, and the matter is now pending before the Ninth Circuit.

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

Preliminary calculations of the ~~City of Seattle’s~~City’s claim for refunds from PSCo are approximately ~~$28~~$28 million, excluding interest, or approximately $60 million, including interest. PSCo has concluded that a loss is reasonably ~~possible with respect to this matter;~~possible; however, given the surrounding uncertainties, PSCo is currently unable to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. ~~In making this assessment, PSCo considered~~ ~~two~~ factors. First, notwithstanding PSCo’s view that the City of Seattle has failed to apply the standard that the FERC has established in this proceeding, and the recognition that this case raises a novel issue and the FERC’s standard has been challenged on appeal to the Ninth Circuit, the outcome of such an appeal cannot be predicted with any certainty. Second, PSCo would expect to make equitable arguments against refunds even if the City of Seattle were to establish that it was overcharged for transactions. If a loss were sustained, PSCo would attempt to recover those losses from other PRPs. No ~~accrual has been recorded for this matter.~~

~~Biomass Fuel Handling Reimbursement —~~ NSP-Minnesota has a PPA through which it procures energy from Fibrominn, LLC (Fibrominn). Under this agreement, NSP-Minnesota is charged for certain costs of transporting biomass fuels that are delivered to Fibrominn’s generation facility. Fibrominn has demanded additional cost reimbursement for certain transportation costs incurred since 2007, as well as reimbursement for similar costs in future periods. Fibrominn claims that it is entitled to reimbursement from NSP-Minnesota for past transportation costs of approximately $20 million. NSP-Minnesota has evaluated Fibrominn’s claim and based on the terms of the PPA with Fibrominn and its current understanding of the facts, NSP-Minnesota disputes the validity of Fibrominn’s claim, on the ground that, among other things, it seeks to impose contractual obligations on NSP-Minnesota that are neither supported by the terms nor the intent of the PPA. NSP-Minnesota has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, NSP-Minnesota is currently unable to determine the amount of reasonably possible loss. If a loss were sustained, NSP-Minnesota would attempt to recover these fuel-related costs in rates. No accrual has been recorded for this matter.

~~Nuclear Power Operations and Waste Disposal~~

~~Nuclear Waste Disposal~~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. Five of the cases have since been settled and seven have been dismissed. One multi-district litigation (MDL) matter remains and it consists of a Colorado class (Breckenridge), a Wisconsin class (NSP-Wisconsin), a Kansas class, and two other cases identified as “Sinclair Oil” and “Farmland.” In ~~1998, NSP-Minnesota~~May 2016, the MDL judge granted summary judgment dismissing defendants from the Farmland lawsuit. e prime and Xcel Energy have filed a ~~complaint~~motion seeking clarification that this order includes them. This motion is currently pending. The e prime defendants recently filed a summary judgment motion in the ~~U.S. Court of Federal Claims against~~Colorado class lawsuit (Breckenridge) and oppositions to class certifications in all the ~~United States requesting breach of contract damages for the DOE’s failure~~class actions. Trial dates have not yet been set, but are not expected to ~~begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contracts between the United States~~occur prior to early 2017. Xcel Energy, NSP-Wisconsin and ~~NSP-Minnesota. NSP-Minnesota sought contract damages in this lawsuit through Dec. 31, 2004. In September 2007, the Court awarded NSP-Minnesota~~ ~~$116.5 million~~ ~~in damages. In August 2007, NSP-Minnesota filed~~e prime have concluded that a ~~second complaint; this lawsuit claimed damages for the period Jan. 1, 2005 through Dec. 31, 2008.~~loss is remote.

Line Extension Disputes — In ~~July 2011,~~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 ~~United States~~terms of electric service agreements entered into by PSCo and ~~NSP-Minnesota executed~~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 CPUC. In June 2016, DRC filed a ~~settlement agreement resolving both lawsuits, providing~~notice of appeal. 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 ~~initial~~ ~~$100 million~~ ~~payment from~~order rejecting DRC’s claims for additional allowances and refunds. In June 2016, the ~~United States~~ALJ’s determination was approved by the CPUC.

PSCo has concluded that a loss is remote with respect to ~~NSP-Minnesota,~~this matter as the service agreements were developed to implement CPUC approved tariffs and ~~providing~~PSCo has complied with the tariff provisions. Also, if a ~~method by which NSP-Minnesota can~~loss were sustained, PSCo believes it would be allowed to recover ~~its spent fuel storage~~these costs through ~~2013, estimated to be an additional~~ ~~$100 million. In January 2014, the United States proposed,~~traditional regulatory mechanisms. The amount or range in dispute is presently unknown and ~~NSP-Minnesota accepted, an extension to the settlement agreement which will allow NSP-Minnesota to recover spent fuel storage costs through 2016. The extension does not address costs~~no accrual has been recorded for spent fuel storage after 2016; such costs could be the subject of future litigation. In December 2014, NSP-Minnesota received a settlement payment of $32.8 million. NSP-Minnesota has received a total of $214.7 million of settlement proceeds as of June 30, 2015. On May 15, 2015, NSP-Minnesota submitted a claim for an additional $13.4 million. Amounts received from the installments, except for approved reductions such as legal costs, will be subsequently returned to customers through a reduction of future rate increases or credited through another regulatory mechanism.this matter.


7.	Borrowings and Other Financing Instruments

Short-Term Borrowings

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

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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 June 30, 2015			Twelve Months Ended Dec. 31, 2014			Three Months Ended June 30, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	2,750		$	2,750		$	2,750		$	2,750
Amount outstanding at period end	451			1,020			447			846
Average amount outstanding	780			841			404			601
Maximum amount outstanding	1,072			1,200			841			1,360
Weighted average interest rate, computed on a daily basis	0.48		%	0.33		%	0.72		%	0.48		%
Weighted average interest rate at period end	0.48			0.56			0.80			0.82

Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At June 30, ~~2015~~2016 and Dec. 31, ~~2014,~~2015, there were ~~$67.8~~$28 million and ~~$60.5~~$29 million, respectively, of letters of credit outstanding under the credit facilities. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facilities — In order to use their commercial paper programs, ~~to fulfill short-term funding needs,~~ Xcel Energy Inc. and its utility subsidiaries must have ~~revolving~~ credit facilities in place at least equal to the amount of their ~~respective~~ commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available ~~capacity under these~~ credit ~~facilities.~~facility capacity. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At June 30, ~~2015,~~2016, 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	$	72	$	928	$	1,000	$	414	$	586
PSCo	700		58		642		700		3		697
NSP-Minnesota	500		144		356		500		18		482
SPS	400		245		155		400		32		368
NSP-Wisconsin	150		—		150		150		8		142
Total	$	2,750	$	519	$	2,231	$	2,750	$	475	$	2,275


^(a)	These credit facilities expire in ~~October 2019.~~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 June 30, ~~2015~~2016 and Dec. 31, ~~2014.~~2015.

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.

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Long-Term Borrowings

During the six months ended June 30, ~~2015,~~2016, Xcel Energy Inc. and its utility subsidiaries completed the following bond issuances:

In ~~May, PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025;~~

~~In June,~~March, Xcel Energy Inc. issued ~~$250~~$400 million of ~~1.2~~2.4 percent senior notes due ~~June 1, 2017~~March 15, 2021 and ~~$250~~$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; and

In June, ~~NSP-Wisconsin~~PSCo issued ~~$100~~$250 million of ~~3.3~~3.55 percent first mortgage bonds due June 15, ~~2024.~~2046.

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8.	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.

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

Specific valuation methods include the following:

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

Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, international equity funds, private equity investments and real estate investments are measured using a net asset ~~values,~~value (NAV) methodology, which ~~take~~takes into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled funds and international equity funds may be redeemed for ~~net asset value~~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. ~~Based on Xcel Energy’s evaluation of its redemption rights, fair value measurements for private equity and real estate investments have been assigned a Level 3.~~

Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

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

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

Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, ~~purchased from MISO, PJM Interconnection, LLC, Electric Reliability Council of Texas, SPP and New York Independent System Operator, generally~~ referred to as financial transmission rights (FTRs). ~~Electric commodity derivatives held by SPS include FTRs purchased from SPP.~~ FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by ~~overall~~ transmission load and ~~other~~ transmission constraints. ~~In addition to overall transmission load, congestion~~Congestion is also influenced by the operating schedules of power plants and the consumption of ~~electricity pertinent to a given transmission path.~~electricity. 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 the limited observability of management’s forecasts for several of the inputs to this complex valuation model ~~– including expected plant operating schedules and retail and wholesale demand,~~ fair value measurements for FTRs have been assigned a Level 3. ~~Non-trading monthly FTR~~Monthly settlements for non-trading FTRs are included in ~~the~~ 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 NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and ~~Prairie Island (PI)~~PI nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.

NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. ~~Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized~~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.~~costs, given the purpose and legal restrictions on the use of nuclear decommissioning fund assets. 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 ~~$335.3~~$336.5 million and ~~$312.1~~$328.8 million at June 30, ~~2015~~2016 and Dec. 31, ~~2014,~~2015, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were ~~$31.4~~$95.2 million and ~~$74.1~~$100.2 million at June 30, ~~2015~~2016 and Dec. 31, ~~2014,~~2015, respectively.

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The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at June 30, ~~2015~~2016 and Dec. 31, ~~2014:~~2015:


	June 30, 2015										June 30, 2016
			Fair Value										Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total		Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	12,446	$	12,446	$	—	$	—	$	12,446	$	15,749	$	15,749	$	—	$	—	$	—	$	15,749
Commingled funds	451,398		—		499,782		—		499,782		389,700		—		—		—		411,788		411,788
International equity funds	123,123		—		121,502		—		121,502		259,090		—		—		—		236,087		236,087
Private equity investments	95,067		—		—		133,993		133,993		119,370		—		—		—		166,054		166,054
Real estate	49,369		—		—		70,834		70,834		72,956		—		—		—		102,144		102,144
Debt securities:
Government securities	24,408		—		22,183		—		22,183		35,199		—		35,828		—		—		35,828
U.S. corporate bonds	69,194		—		66,096		—		66,096		96,110		—		91,350		—		—		91,350
International corporate bonds	16,506		—		16,294		—		16,294		19,959		—		19,394		—		—		19,394
Municipal bonds	209,103		—		210,898		—		210,898		11,966		—		12,826		—		—		12,826
Asset-backed securities	2,831		—		2,851		—		2,851		2,844		—		2,881		—		—		2,881
Mortgage-backed securities	12,039		—		12,219		—		12,219		10,708		—		11,180		—		—		11,180
Equity securities:
Common stock	382,755		583,031		—		—		583,031		479,865		649,521		—		—		—		649,521
Total	$	1,448,239	$	595,477	$	951,825	$	204,827	$	1,752,129	$	1,513,516	$	665,270	$	173,459	$	—	$	916,073	$	1,754,802


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes ~~$81.0~~$133.7 million of equity investments in unconsolidated subsidiaries and ~~$47.0~~$99.0 million of rabbi trust assets and miscellaneous investments.

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


	Dec. 31, 2014										Dec. 31, 2015
			Fair Value										Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total		Cost		Level 1		Level 2		Level 3		Investments Measured at NAV ^(b)		Total
Nuclear decommissioning fund ^(a)
Cash equivalents	$	24,184	$	24,184	$	—	$	—	$	24,184	$	27,484	$	27,484	$	—	$	—	$	—	$	27,484
Commingled funds	470,013		—		465,615		—		465,615		392,838		—		—		—		410,634		410,634
International equity funds	80,454		—		78,721		—		78,721		259,114		—		—		—		231,122		231,122
Private equity investments	73,936		—		—		101,237		101,237		105,965		—		—		—		157,528		157,528
Real estate	43,859		—		—		64,249		64,249		61,816		—		—		—		84,750		84,750
Debt securities:
Government securities	30,674		—		28,808		—		28,808		24,444		—		21,356		—		—		21,356
U.S. corporate bonds	81,463		—		77,562		—		77,562		73,061		—		65,276		—		—		65,276
International corporate bonds	16,950		—		16,341		—		16,341		13,726		—		12,801		—		—		12,801
Municipal bonds	242,282		—		249,201		—		249,201		49,255		—		51,589		—		—		51,589
Asset-backed securities	9,131		—		9,250		—		9,250		2,837		—		2,830		—		—		2,830
Mortgage-backed securities	23,225		—		23,895		—		23,895		11,444		—		11,621		—		—		11,621
Equity securities:
Common stock	369,751		564,858		—		—		564,858		473,615		647,159		—		—		—		647,159
Total	$	1,465,922	$	589,042	$	949,393	$	165,486	$	1,703,921	$	1,495,599	$	674,643	$	165,473	$	—	$	884,034	$	1,724,150


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes ~~$83.1~~$130.0 million of equity investments in unconsolidated subsidiaries and ~~$45.6~~$48.9 million of miscellaneous investments.


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

~~The following tables present~~For the ~~changes in~~six months ended June 30, 2016 and 2015 there were no Level 3 nuclear decommissioning fund investments ~~for the three~~ and ~~six months ended June 30, 2015 and 2014:~~

(Thousands of Dollars) April 1, 2015 Purchases Settlements
Gains Recognized as
Regulatory Assets ^(a)
June 30, 2015
Private equity investments $ 113,619
$ 8,749
$ —
$ 11,625
$ 133,993
Real estate 67,774
4,271
(1,241 ) 30
70,834
Total $ 181,393
$ 13,020
$ (1,241 ) $ 11,655
$ 204,827

(Thousands of Dollars) April 1, 2014 Purchases Settlements
Gains Recognized as
Regulatory Asset ^(a)
June 30, 2014
Private equity investments $ 73,801
$ 2,184
$ —
$ 5,138
$ 81,123
Real estate 62,954
197
—
2,507
65,658
Total $ 136,755
$ 2,381
$ —
$ 7,645
$ 146,781

(Thousands of Dollars) Jan. 1, 2015 Purchases Settlements
Gains Recognized as
Regulatory Assets ^(a)
June 30, 2015
Private equity investments $ 101,237
$ 21,131
$ —
$ 11,625
$ 133,993
Real estate 64,249
8,132
(2,622 ) 1,075
70,834
Total $ 165,486
$ 29,263
$ (2,622 ) $ 12,700
$ 204,827

(Thousands of Dollars) Jan. 1, 2014 Purchases Settlements
Gains Recognized as
Regulatory Asset ^(a)
June 30, 2014
Private equity investments $ 62,696
$ 10,953
$ —
$ 7,474
$ 81,123
Real estate 57,368
3,856
—
4,434
65,658
Total $ 120,064
$ 14,809
$ —
$ 11,908
$ 146,781
no transfers of amounts between levels.


^(a)	~~Gains are deferred as a component of the regulatory assets for nuclear decommissioning.~~

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The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at June 30, ~~2015:~~2016:


	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	$	—	$	—	$	—	$	22,183		$	22,183	$	—	$	10,659	$	982	$	24,187	$	35,828
U.S. corporate bonds	—		14,684		54,005		(2,593		)	66,096		261		26,988		59,368		4,733		91,350
International corporate bonds	—		3,951		11,325		1,018			16,294		—		3,966		12,368		3,060		19,394
Municipal bonds	361		32,427		41,313		136,797			210,898		—		212		4,248		8,366		12,826
Asset-backed securities	—		—		2,851		—			2,851		—		—		2,881		—		2,881
Mortgage-backed securities	—		—		—		12,219			12,219		—		—		—		11,180		11,180
Debt securities	$	361	$	51,062	$	109,494	$	169,624		$	330,541	$	261	$	41,825	$	79,847	$	51,526	$	173,459

Rabbi Trusts

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



	June 30, 2016
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts ^(a)
Cash equivalents	$	47,762	$	47,762	$	—	$	—	$	47,762
Mutual funds	1,593		1,778		—		—		1,778
Total	$	49,355	$	49,540	$	—	$	—	$	49,540


(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.

At June 30, ~~2015,~~2016, accumulated other comprehensive losses related to interest rate derivatives included ~~$3.4~~$3.4 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for ~~any~~ unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. Xcel Energy’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management ~~committee, which is made up of management personnel not directly involved in the activities governed by this policy.~~committee.

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.

Table of Contents

At June 30, ~~2015,~~2016, Xcel Energy had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. Xcel Energy also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and six months ended June 30, ~~2015~~2016 and ~~2014.~~2015.

At June 30, ~~2015,~~2016, net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

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

~~Table of Contents~~

The following table details the gross notional amounts of commodity forwards, options and FTRs at June 30, ~~2015~~2016 and Dec. 31, ~~2014:~~2015:


(Amounts in Thousands) ^(a)(b)	June 30, 2015	Dec. 31, 2014	June 30, 2016	Dec. 31, 2015
Megawatt hours of electricity	97,459	56,361	81,667	50,487
Million British thermal units of natural gas	7,959	927	84,578	20,874
Gallons of vehicle fuel	211	282	70	141


^(a)	Amounts are not reflective of net positions in the underlying commodities.


^(b)	Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

The following tables detail the impact of derivative activity during the three and six months ended June 30, ~~2015~~2016 and ~~2014,~~2015, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:

Three Months Ended June 30, 2015
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)

Derivatives designated as cash flow hedges
Interest rate $ —
$ —
$ 954
^(a)
$ —
$ —

Vehicle fuel and other commodity 29
—
28
^(b)
—
—

Total $ 29
$ —
$ 982
$ —
$ —

Other derivative instruments
Commodity trading $ —
$ —
$ —
$ —
$ 4,401
^(c)
Electric commodity —
(4,737 ) —
(8,037 )
^(d)
—

Natural gas commodity —
(232 ) —
(22 )
^(e)
—

Total $ —
$ (4,969 ) $ —
$ (8,059 ) $ 4,401


	Six Months Ended June 30, 2015																Three Months Ended June 30, 2016
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:							Pre-Tax Gains 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 Gains Recognized During the Period in Income
Interest rate	$	—	$	—		$	1,894	^(a)	$	—			$	—			$	—		$	—			$	1,483	^(a)	$	—		$	—
Vehicle fuel and other commodity	11		—			55		^(b)	—				—				19			—				47		^(b)	—			—
Total	$	11	$	—		$	1,949		$	—			$	—			$	19		$	—			$	1,530		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—			$	8,281	^(c)		$	—		$	—			$	—		$	—		$	481	^(c)
Electric commodity	—		(14,208		)	—			(13,160		)	^(d)	—				—			(705		)		—			16,642		^(d)	—
Natural gas commodity	—		(448		)	—			(8,852		)	^(e)	8,991		^(e)		—			6,063				—			—			25		^(e)
Total	$	—	$	(14,656	)	$	—		$	(22,012	)		$	17,272			$	—		$	5,358			$	—		$	16,642		$	506

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Three Months Ended June 30, 2014
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized
During the Period in Income
(Thousands of Dollars) Accumulated Other
Comprehensive Loss Regulatory
(Assets) and Liabilities Accumulated Other
Comprehensive Loss
Regulatory
Assets and (Liabilities)

Derivatives designated as cash flow hedges
Interest rate $ —
$ —
$ 956
^(a)
$ —
$ —

Vehicle fuel and other commodity 25
—
(17 )
^(b)
—
—

Total $ 25
$ —
$ 939
$ —
$ —

Other derivative instruments
Commodity trading $ —
$ —
$ —
$ —
$ 5,176
^(c)
Electric commodity —
(17,375 ) —
(4,574 )
^(d)
—

Natural gas commodity —
(2,449 ) —
—
(65 )
^(d)
Other commodity —
—
—
—
643
^(c)
Total $ —
$ (19,824 ) $ —
$ (4,574 ) $ 5,754


	Six Months Ended June 30, 2014																		Six Months Ended June 30, 2016
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:								Pre-Tax Gains (Losses) Recognized During the Period in Income					Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:							Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Gains (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
Interest rate	$	—	$	—		$	1,902		^(a)	$	—			$	—				$	—		$	—			$	2,968	^(a)	$	—		$	—
Vehicle fuel and other commodity	14		—			(45		)	^(b)	—				—					13			—				104		^(b)	—			—
Total	$	14	$	—		$	1,857			$	—			$	—				$	13		$	—			$	3,072		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—			$	2,922		^(c)		$	—		$	—			$	—		$	—		$	1,490		^(c)
Electric commodity	—		(13,849		)	—				(25,270		)	^(d)	—					—			(970		)		—			27,533		^(d)	—
Natural gas commodity	—		16,058			—				(18,840		)	^(e)	(5,367		)	^(e)		—			3,361				—			11,666		^(e)	(4,999		)	^(e)
Other commodity	—		—			—				—				643			^(c)
Total	$	—	$	2,209		$	—			$	(44,110	)		$	(1,802	)			$	—		$	2,391			$	—		$	39,199		$	(3,509	)



	Three Months Ended June 30, 2015
	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)				Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	954	^(a)	$	—			$	—
Vehicle fuel and other commodity	29		—			28		^(b)	—				—
Total	$	29	$	—		$	982		$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—			$	4,401	^(c)
Electric commodity	—		(4,737		)	—			(8,037		)	^(d)	—
Natural gas commodity	—		(232		)	—			(22		)	^(e)	—
Total	$	—	$	(4,969	)	$	—		$	(8,059	)		$	4,401



	Six Months Ended June 30, 2015
	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)				Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	1,894	^(a)	$	—			$	—
Vehicle fuel and other commodity	11		—			55		^(b)	—				—
Total	$	11	$	—		$	1,949		$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—			$	8,281	^(c)
Electric commodity	—		(14,208		)	—			(13,160		)	^(d)	—
Natural gas commodity	—		(448		)	—			(8,852		)	^(e)	8,991		^(e)
Total	$	—	$	(14,656	)	$	—		$	(22,012	)		$	17,272


^(a)	Amounts are recorded to interest charges.


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


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


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

^(e)

Amounts for the three and six months ended June 30, 2016 and 2015 ~~and six months ended 2014~~ included an immaterial amount of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three and six months ended June 30, ~~2015~~2016 and ~~six months ended 2014~~2015 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.

Table of Contents

Xcel Energy had no derivative instruments designated as fair value hedges during the three and six months ended June 30, ~~2015~~2016 and ~~2014.~~2015. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Consideration of Credit Risk and Concentrations — Xcel Energy ~~continuously~~ monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the ~~transactions set forth in the contracts.~~transactions. 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 ~~and transmission~~ activities. At June 30, ~~2015, four~~2016, one of Xcel Energy’s 10 most significant counterparties for these activities, comprising ~~$44.6~~$13.5 million or 186 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. ~~The remaining six~~Seven of the 10 most significant counterparties, comprising ~~$71.5~~$55.6 million or 2825 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 10~~The remaining two most significant counterparties, comprising $12.2 million or 6 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external and internal analysis. Nine of these significant counterparties are 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 June 30, ~~2015~~2016 and Dec. 31, ~~2014,~~2015, there were no derivative instruments in a liability position that would have required the posting of collateral or settlement of applicable outstanding contracts if the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment grade.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a ~~given~~ utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of June 30, ~~2015~~2016 and Dec. 31, ~~2014.~~2015.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis at June 30, ~~2015:~~2016:


	June 30, 2015														June 30, 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	$	—	$	11,596	$	7,927	$	19,523	$	(6,849	)		$	12,674	$	5,384	$	14,675	$	—	$	20,059	$	(14,017	)	$	6,042
Electric commodity	—		—		51,355		51,355		(10,600		)		40,755		—		—		28,151		28,151		(3,593		)	24,558
Natural gas commodity	—		253		—		253		(166		)		87		—		8,525		—		8,525		(31		)	8,494
Total current derivative assets	$	—	$	11,849	$	59,282	$	71,131	$	(17,615	)		53,516		$	5,384	$	23,200	$	28,151	$	56,735	$	(17,641	)	39,094
PPAs ^(a)													10,087													7,859
Current derivative instruments													$	63,603												$	46,953
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	23,771	$	—	$	23,771	$	(5,503	)		$	18,268	$	1,037	$	28,058	$	—	$	29,095	$	(6,986	)	$	22,109
Natural gas commodity															—		1,355		—		1,355		—			1,355
Total noncurrent derivative assets	$	—	$	23,771	$	—	$	23,771	$	(5,503	)		18,268		$	1,037	$	29,413	$	—	$	30,450	$	(6,986	)	23,464
PPAs ^(a)													35,038													27,180
Noncurrent derivative instruments													$	53,306												$	50,644

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	June 30, 2015														June 30, 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	$	—	$	106	$	—	$	106	$	—			$	106	$	—	$	82	$	—	$	82	$	—		$	82
Other derivative instruments:
Commodity trading	—		8,338		1,855		10,193		(7,097		)		3,096		5,407		12,740		41		18,188		(14,575		)	3,613
Electric commodity	—		—		10,600		10,600		(10,600		)		—		—		—		3,593		3,593		(3,593		)	—
Natural gas commodity	—		490		—		490		(166		)		324		—		31		—		31		(31		)	—
Other commodity	—		450		—		450		—				450
Total current derivative liabilities	$	—	$	9,384	$	12,455	$	21,839	$	(17,863	)		3,976		$	5,407	$	12,853	$	3,634	$	21,894	$	(18,199	)	3,695
PPAs ^(a)													22,869													22,847
Current derivative instruments													$	26,845												$	26,542
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	49	$	—	$	49	$	—			$	49
Other derivative instruments:
Commodity trading	—		13,853		—		13,853		(11,731		)		2,122		$	1,086	$	19,786	$	—	$	20,872	$	(11,162	)	$	9,710
Other commodity	—		26		—		26		—				26
Total noncurrent derivative liabilities	$	—	$	13,928	$	—	$	13,928	$	(11,731	)		2,197		$	1,086	$	19,786	$	—	$	20,872	$	(11,162	)	9,710
PPAs ^(a)													169,494													146,647
Noncurrent derivative instruments													$	171,691												$	156,357

^(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 June 30, ~~2015.~~2016. At June 30, ~~2015,~~2016, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of ~~$6.5~~$4.7 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.

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, ~~2014:~~2015:


		Dec. 31, 2014															Dec. 31, 2015
		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		$	—	$	14,326	$	4,732	$	19,058	$	(3,240	)		$	15,818		$	225	$	10,620	$	1,250	$	12,095	$	(5,865	)	$	6,230
Electric commodity		—		—		62,825		62,825		(11,402		)		51,423			—		—		21,421		21,421		(4,088		)	17,333
Natural gas commodity		—		381		—		381		(22		)		359			—		496		—		496		(303		)	193
Total current derivative assets	Total current derivative assets	$	—	$	14,707	$	67,557	$	82,264	$	(14,664	)		67,600		Total current derivative assets	$	225	$	11,116	$	22,671	$	34,012	$	(10,256	)	23,756
PPAs ^(a)														18,123														10,086
Current derivative instruments														$	85,723													$	33,842
Noncurrent derivative assets
Other derivative instruments:
Commodity trading		$	—	$	17,617	$	—	$	17,617	$	(4,151	)		$	13,466		$	—	$	27,416	$	—	$	27,416	$	(6,555	)	$	20,861
Total noncurrent derivative assets	Total noncurrent derivative assets	$	—	$	17,617	$	—	$	17,617	$	(4,151	)		13,466		Total noncurrent derivative assets	$	—	$	27,416	$	—	$	27,416	$	(6,555	)	20,861
PPAs ^(a)														40,309														30,222
Noncurrent derivative instruments														$	53,775													$	51,083

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	Dec. 31, 2014														Dec. 31, 2015
	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	$	—	$	118	$	—	$	118	$	—			$	118	$	—	$	205	$	—	$	205	$	—		$	205
Other derivative instruments:
Commodity trading	—		7,974		—		7,974		(7,974		)		—		152		7,866		555		8,573		(6,904		)	1,669
Electric commodity	—		—		11,402		11,402		(11,402		)		—		—		—		4,088		4,088		(4,088		)	—
Natural gas commodity	—		548		—		548		(21		)		527		—		5,407		—		5,407		(303		)	5,104
Total current derivative liabilities	$	—	$	8,640	$	11,402	$	20,042	$	(19,397	)		645		$	152	$	13,478	$	4,643	$	18,273	$	(11,295	)	6,978
PPAs ^(a)													20,987													22,861
Current derivative instruments													$	21,632												$	29,839
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	102	$	—	$	102	$	—			$	102
Other derivative instruments:
Commodity trading	—		6,890		—		6,890		(6,033		)		857		$	—	$	19,898	$	—	$	19,898	$	(9,780	)	$	10,118
Natural gas commodity	—		35		—		35		—				35
Total noncurrent derivative liabilities	$	—	$	7,027	$	—	$	7,027	$	(6,033	)		994		$	—	$	19,898	$	—	$	19,898	$	(9,780	)	10,118
PPAs ^(a)													182,942													158,193
Noncurrent derivative instruments													$	183,936												$	168,311

^(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, ~~2014.~~2015. At Dec. 31, ~~2014,~~2015, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of ~~$6.6 million~~.$4.3 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents the changes in Level 3 commodity derivatives for the three and six months ended June 30, ~~2015~~2016 and ~~2014:~~2015:


	Three Months Ended June 30						Three Months Ended June 30
(Thousands of Dollars)	2015			2014			2016			2015
Balance at April 1	$	17,429		$	24,217		$	6,854		$	17,429
Purchases	57,446			120,107			29,826			57,446
Settlements	(17,315		)	(33,610		)	(14,111		)	(17,315		)
Net transactions recorded during the period:
Gains recognized in earnings ^(a)	1,220			6,438
(Losses) recognized as regulatory assets and liabilities	(11,953		)	(11,758		)
(Losses) gains recognized in earnings ^(a)							(18		)	1,220
Gains (losses) recognized as regulatory assets and liabilities							1,966			(11,953		)
Balance at June 30	$	46,827		$	105,394		$	24,517		$	46,827

							Six Months Ended June 30
(Thousands of Dollars)							2016			2015
Balance at Jan. 1							$	18,028		$	56,155
Purchases							31,670			63,238
Settlements							(26,161		)	(37,246		)
Net transactions recorded during the period:
(Losses) gains recognized in earnings ^(a)							(43		)	1,280
Gains (losses) recognized as regulatory assets and liabilities							1,023			(36,600		)
Balance at June 30							$	24,517		$	46,827

Six Months Ended June 30
(Thousands of Dollars) 2015 2014
Balance at Jan. 1 $ 56,155
$ 41,660
Purchases 63,238
121,164
Settlements (37,246 ) (87,419 )
Net transactions recorded during the period:
Gains recognized in earnings ^(a)
1,280
7,437
(Losses) gains recognized as regulatory assets and liabilities (36,600 ) 22,552
Balance at June 30 $ 46,827
$ 105,394


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

~~Table of Contents~~

Xcel Energy recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and six months ended June 30, ~~2015~~2016 and ~~2014.~~2015.

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Fair Value of Long-Term Debt

As of June 30, ~~2015~~2016 and Dec. 31, ~~2014,~~2015, other financial instruments for which the carrying amount did not equal fair value were as follows:


	June 30, 2015				Dec. 31, 2014				June 30, 2016				Dec. 31, 2015
(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)	$	12,603,482	$	13,585,712	$	11,757,360	$	13,360,236	$	13,814,921	$	15,935,100	$	13,055,901	$	14,094,744


^(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 June 30, ~~2015~~2016 and Dec. 31, ~~2014,~~2015, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.


9.	Other Income, Net

Other income, net consisted of the following:


	Three Months Ended June 30						Six Months Ended June 30						Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2015			2014			2015			2014			2016			2015			2016			2015
Interest income	$	389		$	1,292		$	4,627		$	5,185		$	984		$	389		$	5,054		$	4,627
Other nonoperating income	794			1,293			1,762			2,396			1,496			794			2,176			1,762
Insurance policy expense	(222		)	(2,438		)	(2,267		)	(4,246		)	(920		)	(222		)	(1,420		)	(2,267		)
Other nonoperating expense	—			(65		)	—			(52		)
Other income, net	$	961		$	82		$	4,122		$	3,283		$	1,560		$	961		$	5,810		$	4,122


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 ~~$81.0~~$133.7 million and ~~$83.1~~$130.0 million as of June 30, ~~2015~~2016 and Dec. 31, ~~2014,~~2015, respectively, included in the regulated natural gas utility segment.

~~Table of Contents~~

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.

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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 ~~operating and maintenance (O&M)~~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		Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended June 30, 2015
Three Months Ended June 30, 2016
Operating revenues from external customers	$	2,213,460	$	284,131		$	17,543		$	—		$	2,515,134	$	2,224,142	$	258,899	$	16,808		$	—		$	2,499,849
Intersegment revenues	420		172			—			(592		)	—		421		241		—			(662		)	—
Total revenues	$	2,213,880	$	284,303		$	17,543		$	(592	)	$	2,515,134	$	2,224,563	$	259,140	$	16,808		$	(662	)	$	2,499,849
Net income (loss)	$	214,955	$	(6,883	)	$	(11,141	)	$	—		$	196,931	$	205,440	$	11,933	$	(20,578	)	$	—		$	196,795


(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
Three Months Ended June 30, 2014
Three Months Ended June 30, 2015
Operating revenues from external customers	$	2,297,638	$	369,127	$	18,331		$	—		$	2,685,096	$	2,213,460	$	284,131		$	17,543		$	—		$	2,515,134
Intersegment revenues	437		1,118		—			(1,555		)	—		420		172			—			(592		)	—
Total revenues	$	2,298,075	$	370,245	$	18,331		$	(1,555	)	$	2,685,096	$	2,213,880	$	284,303		$	17,543		$	(592	)	$	2,515,134
Net income (loss)	$	185,677	$	15,297	$	(5,810	)	$	—		$	195,164	$	214,955	$	(6,883	)	$	(11,141	)	$	—		$	196,931


(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
Six Months Ended June 30, 2015
Six Months Ended June 30, 2016
Operating revenues from external customers	$	4,438,323		$	1,000,127	$	38,903		$	—		$	5,477,353	$	4,409,261	$	824,588	$	38,273		$	—		$	5,272,122
Intersegment revenues	750			848		—			(1,598		)	—		756		528		—			(1,284		)	—
Total revenues	$	4,439,073		$	1,000,975	$	38,903		$	(1,598	)	$	5,477,353	$	4,410,017	$	825,116	$	38,273		$	(1,284	)	$	5,272,122
Net income (loss)	$	295,976	^(a)	$	76,793	$	(23,772	)	$	—		$	348,997	$	383,677	$	90,271	$	(35,841	)	$	—		$	438,107


(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
Six Months Ended June 30, 2014
Six Months Ended June 30, 2015
Operating revenues from external customers	$	4,599,348	$	1,248,815	$	39,537		$	—		$	5,887,700	$	4,438,323		$	1,000,127	$	38,903		$	—		$	5,477,353
Intersegment revenues	790		4,370		—			(5,160		)	—		750			848		—			(1,598		)	—
Total revenues	$	4,600,138	$	1,253,185	$	39,537		$	(5,160	)	$	5,887,700	$	4,439,073		$	1,000,975	$	38,903		$	(1,598	)	$	5,477,353
Net income (loss)	$	371,110	$	92,633	$	(7,358	)	$	—		$	456,385	$	295,976	^(a)	$	76,793	$	(23,772	)	$	—		$	348,997


^(a)	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.

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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.

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, 2015					Three Months Ended June 30, 2014					Three Months Ended June 30, 2016					Three Months Ended June 30, 2015
(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	$	196,931	—	—		$	195,164	—	—		$	196,795	—	—		$	196,931	—	—
Basic EPS:
Earnings available to common shareholders	196,931		507,707	$	0.39	195,164		503,272	$	0.39	196,795		508,930	$	0.39	196,931		507,707	$	0.39
Effect of dilutive securities:
Time based equity awards	—		367	—		—		184	—		—		560	—		—		367	—
Diluted EPS:
Earnings available to common shareholders	$	196,931	508,074	$	0.39	$	195,164	503,456	$	0.39	$	196,795	509,490	$	0.39	$	196,931	508,074	$	0.39


	Six Months Ended June 30, 2015					Six Months Ended June 30, 2014					Six Months Ended June 30, 2016					Six Months Ended June 30, 2015
(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	$	348,997	—	—		$	456,385	—	—		$	438,107	—	—		$	348,997	—	—
Basic EPS:
Earnings available to common shareholders	348,997		507,359	$	0.69	456,385		501,408	$	0.91	438,107		508,789	$	0.86	348,997		507,359	$	0.69
Effect of dilutive securities:
Time based equity awards	—		388	—		—		204	—		—		522	—		—		388	—
Diluted EPS:
Earnings available to common shareholders	$	348,997	507,747	$	0.69	$	456,385	501,612	$	0.91	$	438,107	509,311	$	0.86	$	348,997	507,747	$	0.69


12.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)


	Three Months Ended June 30												Three Months Ended June 30
	2015			2014			2015			2014			2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits						Pension Benefits						Postretirement Health Care Benefits
Service cost	$	24,828		$	22,085		$	529		$	864		$	22,945		$	24,828		$	431		$	529
Interest cost	37,131			39,155			6,324			8,507			40,028			37,131			6,526			6,324
Expected return on plan assets	(53,472		)	(51,801		)	(6,650		)	(8,488		)	(52,575		)	(53,472		)	(6,248		)	(6,650		)
Amortization of prior service credit	(451		)	(436		)	(2,671		)	(2,672		)	(477		)	(451		)	(2,671		)	(2,671		)
Amortization of net loss	31,288			29,190			1,351			2,935			24,385			31,288			1,009			1,351
Net periodic benefit cost (credit)	39,324			38,193			(1,117		)	1,146			34,306			39,324			(953		)	(1,117		)
Costs not recognized due to the effects of regulation	(7,523		)	(6,604		)	—			—			(4,159		)	(7,523		)	—			—
Net benefit cost (credit) recognized for financial reporting	$	31,801		$	31,589		$	(1,117	)	$	1,146		$	30,147		$	31,801		$	(953	)	$	(1,117	)

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	Six Months Ended June 30												Six Months Ended June 30
	2015			2014			2015			2014			2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits						Pension Benefits						Postretirement Health Care Benefits
Service cost	$	49,656		$	44,171		$	1,058		$	1,728		$	45,865		$	49,656		$	863		$	1,058
Interest cost	74,262			78,310			12,648			17,014			80,051			74,262			13,053			12,648
Expected return on plan assets	(106,945		)	(103,602		)	(13,300		)	(16,977		)	(105,150		)	(106,945		)	(12,497		)	(13,300		)
Amortization of prior service credit	(902		)	(873		)	(5,343		)	(5,344		)	(961		)	(902		)	(5,343		)	(5,343		)
Amortization of net loss	62,576			58,381			2,702			5,870			48,770			62,576			2,020			2,702
Net periodic benefit cost (credit)	78,647			76,387			(2,235		)	2,291			68,575			78,647			(1,904		)	(2,235		)
Costs not recognized due to the effects of regulation	(15,019		)	(13,656		)	—			—			(8,611		)	(15,019		)	—			—
Net benefit cost (credit) recognized for financial reporting	$	63,628		$	62,731		$	(2,235	)	$	2,291		$	59,964		$	63,628		$	(1,904	)	$	(2,235	)

In January ~~2015,~~2016, contributions of ~~$90.0~~$125.0 million were made across four of Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during ~~2015.~~2016.


13.	Other Comprehensive Income

Changes in accumulated other comprehensive (loss) income, net of tax, for the three and six months ended June 30, ~~2015~~2016 and ~~2014~~2015 were as follows:


	Three Months Ended June 30, 2015											Three 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			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	$	(57,054	)	$	111	$	(49,745	)	$	(106,688	)	$	(53,928	)	$	110	$	(54,790	)	$	(108,608	)
Other comprehensive income before reclassifications	18			1		—			19			12			—		—			12
Losses reclassified from net accumulated other comprehensive loss	600			—		883			1,483			936			—		865			1,801
Net current period other comprehensive income	618			1		883			1,502			948			—		865			1,813
Accumulated other comprehensive (loss) income at June 30	$	(56,436	)	$	112	$	(48,862	)	$	(105,186	)	$	(52,980	)	$	110	$	(53,925	)	$	(106,795	)


	Three Months Ended June 30, 2014											Three Months Ended June 30, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains 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 April 1	$	(59,200	)	$	115	$	(45,735	)	$	(104,820	)	$	(57,054	)	$	111	$	(49,745	)	$	(106,688	)
Other comprehensive income before reclassifications	16			—		—			16			18			1		—			19
Losses reclassified from net accumulated other comprehensive loss	574			—		864			1,438			600			—		883			1,483
Net current period other comprehensive income	590			—		864			1,454			618			1		883			1,502
Accumulated other comprehensive (loss) income at June 30	$	(58,610	)	$	115	$	(44,871	)	$	(103,366	)	$	(56,436	)	$	112	$	(48,862	)	$	(105,186	)



	Six 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 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	)

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Six Months Ended June 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 Jan. 1 $ (57,628 ) $ 110
$ (50,621 ) $ (108,139 )
Other comprehensive income before reclassifications 7
2
—
9
Losses reclassified from net accumulated other comprehensive loss 1,185
—
1,759
2,944
Net current period other comprehensive income 1,192
2
1,759
2,953
Accumulated other comprehensive (loss) income at June 30 $ (56,436 ) $ 112
$ (48,862 ) $ (105,186 )


	Six Months Ended June 30, 2014											Six Months Ended June 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			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	$	(59,753	)	$	77	$	(46,599	)	$	(106,275	)	$	(57,628	)	$	110	$	(50,621	)	$	(108,139	)
Other comprehensive income before reclassifications	8			38		—			46			7			2		—			9
Losses reclassified from net accumulated other comprehensive loss	1,135			—		1,728			2,863			1,185			—		1,759			2,944
Net current period other comprehensive income	1,143			38		1,728			2,909			1,192			2		1,759			2,953
Accumulated other comprehensive (loss) income at June 30	$	(58,610	)	$	115	$	(44,871	)	$	(103,366	)	$	(56,436	)	$	112	$	(48,862	)	$	(105,186	)

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, ~~2015~~2016 and ~~2014~~2015 were as follows:


	Amounts Reclassified from Accumulated Other Comprehensive Loss								Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2015				Three Months Ended June 30, 2014				Three Months Ended June 30, 2016				Three Months Ended June 30, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	954		^(a)	$	956		^(a)	$	1,483		^(a)	$	954		^(a)
Vehicle fuel derivatives	28			^(b)	(17		)	^(b)	47			^(b)	28			^(b)
Total, pre-tax	982				939				1,530				982
Tax benefit	(382		)		(365		)		(594		)		(382		)
Total, net of tax	600				574				936				600
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	1,533			^(c)	1,500			^(c)	1,478			^(c)	1,533			^(c)
Prior service credit	(89		)	^(c)	(86		)	^(c)	(64		)	^(c)	(89		)	^(c)
Total, pre-tax	1,444				1,414				1,414				1,444
Tax benefit	(561		)		(550		)		(549		)		(561		)
Total, net of tax	883				864				865				883
Total amounts reclassified, net of tax	$	1,483			$	1,438			$	1,801			$	1,483

~~Table of Contents~~


	Amounts Reclassified from Accumulated Other Comprehensive Loss								Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2015				Six Months Ended June 30, 2014				Six Months Ended June 30, 2016				Six Months Ended June 30, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	1,894		^(a)	$	1,902		^(a)	$	2,968		^(a)	$	1,894		^(a)
Vehicle fuel derivatives	55			^(b)	(45		)	^(b)	104			^(b)	55			^(b)
Total, pre-tax	1,949				1,857				3,072				1,949
Tax benefit	(764		)		(722		)		(1,198		)		(764		)
Total, net of tax	1,185				1,135				1,874				1,185
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	3,068			^(c)	2,999			^(c)	2,956			^(c)	3,068			^(c)
Prior service (credit) cost	(179		)	^(c)	(172		)	^(c)
Prior service credit									(128		)	^(c)	(179		)	^(c)
Total, pre-tax	2,889				2,827				2,828				2,889
Tax benefit	(1,130		)		(1,099		)		(1,099		)		(1,130		)
Total, net of tax	1,759				1,728				1,729				1,759
Total amounts reclassified, net of tax	$	2,944			$	2,863			$	3,603			$	2,944


^(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.

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed ~~in the following discussion and analysis~~herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including ~~the 2015~~our 2016 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 ~~do not undertake~~expressly disclaim any obligation to update ~~them~~any forward-looking information. The following factors, in addition to ~~reflect changes that occur after that date. Factors that~~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 Report on Form 10-Q for the quarter ended March 31, 2016), could cause actual results to differ materially ~~include, but are not limited to:~~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,~~industry; including the risk of a slow down in the U.S. economy or delay in growth, ~~recovery;~~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 ~~Inc.~~ 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; ~~actions by regulatory bodies impacting our nuclear operations, including those affecting costs, operations or the approval of requests pending before the NRC;~~ financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability orof cost of capital; and employee work force factors; the items described under Factors Affecting Results of Operations in Item 7 of Xcel Energy Inc.’s Form 10-K for the year ended Dec. 31, 2014; and the other risk factors listed from time to time by Xcel Energy in reports filed with the SEC, including Risk Factors in Item 1A and Exhibit 99.01 of Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2014, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended June 30, 2015.factors.

~~Table of Contents~~

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 the diluted EPS for Xcel Energy:


	Three Months Ended June 30						Six Months Ended June 30						Three Months Ended June 30						Six Months Ended June 30
Diluted Earnings (Loss) Per Share	2015			2014			2015			2014			2016			2015			2016			2015
PSCo	$	0.19		$	0.18		$	0.41		$	0.41		$	0.17		$	0.19		$	0.40		$	0.41
NSP-Minnesota	0.15			0.15			0.32			0.37			0.15			0.15			0.34			0.32
SPS	0.05			0.06			0.08			0.09			0.06			0.05			0.11			0.08
NSP-Wisconsin	0.02			0.02			0.07			0.07			0.02			0.02			0.06			0.07
Equity earnings of unconsolidated subsidiaries	0.01			0.01			0.02			0.02			0.01			0.01			0.03			0.02
Regulated utility(a)	0.42			0.42			0.90			0.96			0.42			0.42			0.93			0.90
Xcel Energy Inc. and other	(0.03		)	(0.03		)	(0.05		)	(0.05		)	(0.04		)	(0.03		)	(0.07		)	(0.05		)
Ongoing diluted EPS(a)	0.39			0.39			0.85			0.91			0.39			0.39			0.86			0.85
Loss on Monticello LCM/EPU project	—			—			(0.16		)	—			—			—			—			(0.16		)
GAAP diluted EPS	$	0.39		$	0.39		$	0.69		$	0.91		$	0.39		$	0.39		$	0.86		$	0.69


^(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 six months ended June 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 ~~allow~~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.~~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 were flat for the second quarter of ~~2015~~2016 and ~~decreased $0.06~~increased $0.01 per share year-to-date, which excludes anthe 2015 adjustment for a charge related to the NSP-Minnesota Monticello LCM/EPU project. ~~Electric margin increased~~Higher electric and gas margins in the second quarter of 2016 were primarily due to ~~new~~higher retail electric and natural gas rates ~~and riders in~~across various jurisdictions, non-fuel riders and ~~a lower PSCo earnings test refund that was partially offset by weather-normalized sales decline and unfavorable~~the impact of favorable weather. ~~This increase was~~These positive factors were offset by higher depreciation, ~~lower allowance for funds used during construction, higher~~interest charges and property ~~taxes, operating and maintenance expenses and interest charges.~~taxes.

PSCo — PSCo’s ongoing earnings ~~increased $0.01~~decreased $0.02 per share for the second quarter of ~~2015~~2016 and ~~were flat~~$0.01 per share year-to-date. ~~The~~Year-to-date, the positive impact of ~~implementing~~higher natural gas revenues due to rate increases was more than offset by higher depreciation, O&M expenses, interest charges and the ~~CACJA rider, effective in January 2015, and lower~~favorable impact of an adjustment to the estimated electric earnings test ~~refunds were offset by lower AFUDC, higher property taxes, depreciation, and O&M expenses, as well as the impact of weather and weather-normalized sales decline.~~refund obligation recognized in 2015.

~~Table of Contents~~

NSP-Minnesota — NSP-Minnesota’s ongoing earnings were flat for the second quarter of ~~2015~~2016 and ~~decreased $0.05~~increased $0.02 per share year-to-date. ~~Higher revenue attributable to~~Year-to-date, higher electric revenues driven by a rate ~~cases~~increase in Minnesota ~~North Dakota~~(interim, subject to refund) and ~~South Dakota~~non-fuel riders were ~~more than~~partially offset by ~~increases in~~higher depreciation, property taxes, O&M expenses ~~property taxes~~ and interest ~~charges, as well as unfavorable weather and weather-normalized sales decline.~~charges.

SPS — SPS’ ongoing earnings ~~decreased~~increased $0.01 ~~per share~~ for the second quarter of ~~2015~~2016 and $0.03 per share year-to-date. ~~Higher~~Year-to-date, higher electric ~~rates in Texas~~margin and lower O&M expenses were partially offset by ~~higher O&M expenses, depreciation, and lower AFUDC, along with the impact of unfavorable weather.~~additional depreciation.

NSP-Wisconsin— NSP-Wisconsin’s ongoing earnings per share were flat for the second quarter of ~~2015~~2016 and decreased $0.01 year-to-date. ~~Lower O&M expenses and~~Year-to-date, higher electric margins primarily ~~due to~~driven by an electric rate increase were more than offset by higher ~~depreciation~~O&M expenses and ~~unfavorable weather.~~depreciation.

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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 second quarter of 2016 and $0.02 per share year-to-date. The change was primarily related to higher long-term debt levels.

Changes in Diluted EPS

The following table summarizes significant components contributing to the changes in ~~2015~~2016 EPS compared with the same period in ~~2014:~~2015:


Diluted Earnings (Loss) Per Share	Three Months Ended June 30			Six Months Ended June 30			Three Months Ended June 30			Six Months Ended June 30
2014 GAAP and ongoing diluted EPS	$	0.39		$	0.91
2015 GAAP diluted EPS							$	0.39		$	0.69
Loss on Monticello LCM/EPU project							—			0.16
2015 ongoing diluted EPS							0.39			0.85

Components of change — 2015 vs. 2014
Higher electric margins	0.06			0.11
Lower conservation and DSM program expenses (offset by lower revenues)	0.02			0.05
Components of change — 2016 vs. 2015
Higher electric margins^(a)							0.07			0.13
Higher natural gas margins ^(b)							0.01			0.03
Lower O&M expenses							—			0.01
Higher depreciation and amortization	(0.02		)	(0.06		)	(0.06		)	(0.11		)
Higher O&M expenses	(0.01		)	(0.04		)
Lower AFUDC — equity	(0.02		)	(0.04		)
Higher interest charges							(0.02		)	(0.04		)
Higher taxes (other than income taxes)	(0.02		)	(0.03		)	(0.01		)	(0.02		)
Higher ETR	(0.01		)	(0.03		)
Lower natural gas margins	—			(0.02		)
Higher interest charges	(0.01		)	(0.01		)
Other, net	0.01			0.01			0.01			0.01
2015 ongoing diluted EPS	0.39			0.85
Loss on Monticello LCM/EPU project	—			(0.16		)
2015 GAAP diluted EPS	$	0.39		$	0.69
2016 GAAP and ongoing diluted EPS							$	0.39		$	0.86

~~The following tables summarize~~^(a)Reflects $0.022 and $0.008 attributable to weather for the ~~earnings contributions of Xcel Energy’s business segments:~~three and six months ended June 30, 2016, respectively.

Three Months Ended June 30 Six Months Ended June 30
(Millions of Dollars) 2015 2014 2015 2014
GAAP income (loss) by segment
Regulated electric income $ 215.0
$ 185.7
$ 296.0
$ 371.1
Regulated natural gas income (6.9 ) 15.3
76.8
92.6
Other (loss) income ^(a)
4.5
8.7
2.3
20.1
Xcel Energy Inc. and other ^(a)
(15.7 ) (14.5 ) (26.1 ) (27.4 )
Total net income $ 196.9
$ 195.2
$ 349.0
$ 456.4

~~Table of Contents~~

Three Months Ended June 30 Six Months Ended June 30
Contributions to Diluted Earnings (Loss) Per Share 2015 2014 2015 2014
GAAP earnings (loss) by segment
Regulated electric $ 0.42
$ 0.37
$ 0.58
$ 0.74
Regulated natural gas (0.01 ) 0.03
0.15
0.18
Other ^(a)
0.01
0.02
0.01
0.04
Xcel Energy Inc. and other ^(a)
(0.03 ) (0.03 ) (0.05 ) (0.05 )
Total diluted EPS $ 0.39
$ 0.39
$ 0.69
$ 0.91


^(a)^(b)Reflects $0.001 and $(0.008) attributable to weather for the three and six months ended June 30, 2016, respectively.	~~Not a reportable segment. Included in all other segment results in Note 10 to the consolidated financial statements.~~

Statement of Income Analysis

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

Estimated Impact of Temperature Changes on Regulated Earnings — 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 ~~cooling degree-day,~~CDD, and each degree of temperature below 65° Fahrenheit is counted as one ~~heating degree-day.~~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.

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


	Three Months Ended June 30						Six Months Ended June 30						Three Months Ended June 30						Six Months Ended June 30
	2015 vs. Normal		2014 vs. Normal		2015 vs. 2014		2015 vs. Normal		2014 vs. Normal		2015 vs. 2014		2016 vs. Normal		2015 vs. Normal		2016 vs. 2015		2016 vs. Normal		2015 vs. Normal		2016 vs. 2015
HDD	(8.1	)%	4.5	%	(12.4	)%	(2.4	)%	12.3	%	(13.2	)%	(3.7	)%	(8.1	)%	4.9	%	(11.5	)%	(2.4	)%	(8.6	)%
CDD	(19.1	)	0.6		(16.8	)	(19.2	)	1.0		(17.4	)	1.7		(19.1	)	25.8		1.7		(19.2	)	26.4
THI	(20.8	)	9.3		(25.1	)	(21.0	)	8.4		(25.2	)	15.8		(20.8	)	45.5		15.4		(21.0	)	45.6

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


	Three Months Ended June 30								Six Months Ended June 30								Three Months Ended June 30								Six Months Ended June 30
	2015 vs. Normal			2014 vs. Normal		2015 vs. 2014			2015 vs. Normal			2014 vs. Normal		2015 vs. 2014			2016 vs. Normal			2015 vs. Normal			2016 vs. 2015		2016 vs. Normal				2015 vs. Normal			2016 vs. 2015
Retail electric	$	(0.013	)	$	0.002	$	(0.015	)	$	(0.013	)	$	0.034	$	(0.047	)	$	0.009	^(a)	$	(0.013	)	$	0.022	$	(0.005	)	^(a)	$	(0.013	)	$	0.008
Firm natural gas	(0.001		)	0.001		(0.002		)	(0.005		)	0.019		(0.024		)	—			(0.001		)	0.001		(0.013		)		(0.005		)	(0.008		)
Total	$	(0.014	)	$	0.003	$	(0.017	)	$	(0.018	)	$	0.053	$	(0.071	)	$	0.009		$	(0.014	)	$	0.023	$	(0.018	)		$	(0.018	)	$	—

~~Table of Contents~~


^(a)	Excludes $0.006 and $0.001 favorable weather impact due to electric sales decoupling at NSP-Minnesota for the three and six months ended June 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 ~~2015:~~2016:


	Three Months Ended June 30										Three Months Ended June 30
	Xcel Energy		PSCo		NSP-Minnesota		NSP-Wisconsin		SPS		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential ^(a)	(4.2	)%	0.5	%	(6.4	)%	(11.4	)%	(5.7	)%	5.6	%	4.8	%	(0.9	)%	4.6	%	4.3	%
Electric commercial and industrial	(1.3	)	(1.7	)	(0.2	)	0.5		(2.9	)	(1.7	)	(0.7	)	1.0		—		(0.6	)
Total retail electric sales	(2.1	)	(1.1	)	(2.0	)	(2.8	)	(3.6	)	0.5		0.8		0.7		1.0		0.7
Firm natural gas sales	(16.7	)	(8.0	)	(31.6	)	(26.0	)	N/A		7.5		4.2		N/A		(6.4	)	5.8


	Three Months Ended June 30										Three Months Ended June 30
	Xcel Energy		PSCo		NSP-Minnesota		NSP-Wisconsin		SPS		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized
Electric residential ^(a)	(2.3	)%	(1.2	)%	(3.0	)%	(6.3	)%	(0.5	)%	3.9	%	0.1	%	(5.6	)%	0.8	%	0.7	%
Electric commercial and industrial	(0.7	)	(2.3	)	0.4		1.4		(1.3	)	(2.2	)	(1.7	)	(0.5	)	(0.7	)	(1.5	)
Total retail electric sales	(1.2	)	(1.9	)	(0.6	)	(0.7	)	(1.3	)	(0.4	)	(1.2	)	(1.4	)	(0.4	)	(0.9	)
Firm natural gas sales	(14.9	)	(13.7	)	(17.4	)	(16.6	)	N/A		5.5		1.6		N/A		(9.7	)	3.4


	Six Months Ended June 30										Six Months Ended June 30
	Xcel Energy		PSCo		NSP-Minnesota		NSP-Wisconsin		SPS		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential ^(a)	(4.6	)%	(1.5	)%	(6.3	)%	(9.2	)%	(4.2	)%	3.3	%	(0.1	)%	(3.8	)%	(2.2	)%	0.5	%
Electric commercial and industrial	(0.6	)	(0.7	)	(0.9	)	1.0		(0.6	)	(1.1	)	(1.0	)	0.5		(0.5	)	(0.6	)
Total retail electric sales	(1.8	)	(0.9	)	(2.6	)	(2.2	)	(1.4	)	0.3		(0.7	)	(0.2	)	(1.1	)	(0.3	)
Firm natural gas sales	(11.8	)	(9.1	)	(15.9	)	(13.5	)	N/A		3.2		(9.4	)	N/A		(12.4	)	(2.0	)

Table of Contents


	Six Months Ended June 30										Six Months Ended June 30
	Xcel Energy		PSCo		NSP-Minnesota		NSP-Wisconsin		SPS		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized
Electric residential ^(a)	(1.3	)%	(1.1	)%	(1.8	)%	(3.4	)%	0.8	%	2.5	%	(0.3	)%	(2.6	)%	(1.0	)%	0.4	%
Electric commercial and industrial	0.1		(0.6	)	—		2.3		0.3		(1.4	)	(1.2	)	(0.1	)	(0.5	)	(1.0	)
Total retail electric sales	(0.4	)	(0.8	)	(0.5	)	0.6		0.3		(0.1	)	(1.0	)	(0.5	)	(0.7	)	(0.6	)
Firm natural gas sales	(2.0	)	(2.5	)	(1.4	)	—		N/A		1.2		(0.2	)	N/A		(3.6	)	0.4



	Six Months Ended June 30 (Excluding Leap Day) ^(b)
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized - adjusted for leap day
Electric residential ^(a)	1.9	%	(0.9	)%	(3.2	)%	(1.6	)%	(0.2	)%
Electric commercial and industrial	(2.0	)	(1.8	)	(0.6	)	(1.0	)	(1.5	)
Total retail electric sales	(0.7	)	(1.5	)	(1.1	)	(1.3	)	(1.1	)
Firm natural gas sales	0.4		(1.0	)	N/A		(4.5	)	(0.4	)


^(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) In order to assess comparable periods, Xcel Energy excluded the estimated impact of the 2016 leap day to present a more comparable year-over-year presentation. The estimated impact of the additional day of sales in 2016 was approximately 50-60 basis points for retail electric and 80-90 basis points for firm natural gas for the sixth months ended.

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

SPS’ commercial and industrial (C&I) growth was driven by continued expansion from oil and gas exploration and production in the Southeastern New Mexico, Permian Basin area. This was partially offset by the impact of wet weather which resulted in less irrigation by agricultural customers. ResidentialPSCo’s residential growth reflects an increased number of customers. The commercial and industrial (C&I) decline was mainly due to lower sales to certain large customers that support the mining industry and oil and gas industries.

NSP-Minnesota’s residential sales decreased primarily due to lower use per customer, partially offset by an increase in customer additions. The C&I sales declined as a result of lower use by large customers primarily in the manufacturing industry. The sales decrease was partially mitigated by an increase in the number of customers within the small customer class.

SPS’ residential sales decline was primarily the result of lower use per customer, partially offset by customer additions. The C&I sales decreased as a result of reduced activity within the oil and gas industries for the small customer class. The decline was partially reduced by customer additions in both the large and small customer classes.

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

~~NSP-Wisconsin’s electric sales growth was largely due to strong sales to~~customer in the large C&I ~~customers primarily in~~class for the oil and gas ~~and sand mining~~ industries. ~~Residential decline was primarily attributable to lower use per customer.~~

PSCo’s C&I decline was primarily due to customers in fracking and certain manufacturing industries. Residential decrease was primarily the result of weaker use per customer, partially offset by customer growth.

NSP-Minnesota’s C&I electric sales were flat as a result of higher use for large customer class (particularly due to greater usage in the petroleum industry), and an increase in the number of customers in both the small and large classes, offset by lower use for small customers in various industries. The residential decrease was due to less use per customer, partially offset by increasing customer growth.

~~Table of Contents~~

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

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

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 June 30						Six Months Ended June 30						Three Months Ended June 30						Six Months Ended June 30
(Millions of Dollars)	2015			2014			2015			2014			2016			2015			2016			2015
Electric revenues	$	2,213		$	2,298		$	4,438		$	4,599		$	2,224		$	2,213		$	4,409		$	4,438
Electric fuel and purchased power	(905		)	(1,041		)	(1,855		)	(2,109		)	(856		)	(905		)	(1,718		)	(1,855		)
Electric margin	$	1,308		$	1,257		$	2,583		$	2,490		$	1,368		$	1,308		$	2,691		$	2,583

Table of Contents

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

Electric Revenues

(Millions of Dollars) Three Months
Ended June 30
2015 vs. 2014 Six Months
Ended June 30
2015 vs. 2014
Fuel and purchased power cost recovery $ (145 ) $ (255 )
Estimated impact of weather (12 ) (37 )
Conservation and DSM program revenues (offset by expenses) (13 ) (28 )
Retail sales growth, excluding weather impact (9 ) (10 )
Non-fuel riders ^{(a) (b)}
31
65
Retail rate increases ^(b)
25
48
PSCO earnings test refund 24
35
Transmission revenue 14
22
Other, net —
(1 )
Total decrease in electric revenues $ (85 ) $ (161 )

~~Electric Margin~~

(Millions of Dollars) Three Months
Ended June 30
2015 vs. 2014 Six Months
Ended June 30
2015 vs. 2014
Non-fuel riders ^{(a) (b)}
$ 31
$ 65
Retail rate increases ^(b)
25
48
PSCo earnings test refund 24
35
NSP-Wisconsin fuel recovery 3
9
Estimated impact of weather (12 ) (37 )
Conservation and DSM program revenues (offset by expenses) (13 ) (28 )
Retail sales decline, excluding weather impact (9 ) (10 )
Other, net 2
11
Total increase in electric margin $ 51
$ 93



(Millions of Dollars)	Three Months Ended June 30 2016 vs. 2015			Six Months Ended June 30 2016 vs. 2015
Fuel and purchased power cost recovery	$	(68	)	$	(148	)
PSCo earnings test refund	(6		)	(6		)
Trading	4			(4		)
Weather decoupling-Minnesota	(5		)	(1		)
Retail rate increases ^(a)	30			68
Transmission revenue	26			37
Non-fuel riders	3			10
Estimated impact of weather	22			8
Other, net	5			7
Total increase (decrease) in electric revenues	$	11		$	(29	)


^(a)	~~Increases relate~~Increase is primarily related to the ~~new CACJA rider in Colorado ($28 million~~Minnesota Electric Rate Case (interim, subject to and ~~$52 million, respectively)~~net of estimated provision for refund) and ~~TCR rider in Minnesota ($5 million and $14 million, respectively).~~Wisconsin.

Electric Margin



(Millions of Dollars)	Three Months Ended June 30 2016 vs. 2015			Six Months Ended June 30 2016 vs. 2015
Retail rate increases ^(a)	$	30		$	68
Transmission revenue, net of costs	11			12
Non-fuel riders	3			10
Estimated impact of weather	22			8
PSCo earnings test refund	(6		)	(6		)
Weather decoupling-Minnesota	(5		)	(1		)
Other, net	5			17
Total increase in electric margin	$	60		$	108

^(b)(a)

Increase is primarily due to rate proceedings in Minnesota ~~Texas, South Dakota, North Dakota, New Mexico, Wisconsin~~(interim, subject to and ~~Michigan. These increases were partially offset by a decline in Colorado retail base rates, which was more than offset by increased CACJA rider revenue as approved by the CPUC in the first quarter~~net of ~~2015.~~ estimated provision for refund) and Wisconsin.

~~Table of Contents~~

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 ~~to recover current expenses~~ for sales to retail customers, fluctuations in the cost of natural gas ~~have little effect~~has minimal impact on natural gas margin. The following table details natural gas revenues and margin:


	Three Months Ended June 30						Six Months Ended June 30						Three Months Ended June 30						Six Months Ended June 30
(Millions of Dollars)	2015			2014			2015			2014			2016			2015			2016			2015
Natural gas revenues	$	284		$	369		$	1,000		$	1,249		$	259		$	284		$	825		$	1,000
Cost of natural gas sold and transported	(127		)	(211		)	(599		)	(835		)	(90		)	(127		)	(402		)	(599		)
Natural gas margin	$	157		$	158		$	401		$	414		$	169		$	157		$	423		$	401

Table of Contents

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

Natural Gas Revenues


(Millions of Dollars)	Three Months Ended June 30 2015 vs. 2014			Six Months Ended June 30 2015 vs. 2014			Three Months Ended June 30 2016 vs. 2015			Six Months Ended June 30 2016 vs. 2015
Purchased natural gas adjustment clause recovery	$	(84	)	$	(234	)	$	(36	)	$	(196	)
Estimated impact of weather	(2		)	(19		)	1			(6		)
Conservation and DSM program revenues (offset by expenses)	(3		)	(11		)
Integrity rider (Colorado) and infrastructure rider (Minnesota), partially offset in expenses	11			18
Retail sales decline, excluding weather impact	(7		)	(3		)
Retail rate increases^(a)							11			24
Other, net	—			—			(1		)	3
Total decrease in natural gas revenues	$	(85	)	$	(249	)	$	(25	)	$	(175	)

^(a) Increase is primarily related to Colorado.

Natural Gas Margin

(Millions of Dollars) Three Months
Ended June 30
2015 vs. 2014 Six Months
Ended June 30
2015 vs. 2014
Estimated impact of weather $ (2 ) $ (19 )
Conservation and DSM program revenues (offset by expenses) (3 ) (11 )
Retail sales decline, excluding weather impact (7 ) (3 )
Integrity rider (Colorado) and infrastructure rider (Minnesota), partially offset in expenses 11
18
Other, net —
2
Total decrease in natural gas margin $ (1 ) $ (13 )



(Millions of Dollars)	Three Months Ended June 30 2016 vs. 2015		Six Months Ended June 30 2016 vs. 2015
Retail rate increases^(a)	$	11	$	24
Estimated impact of weather	1		(6		)
Other, net	—		4
Total increase in natural gas margin	$	12	$	22

^(a) Increase is primarily related to Colorado.

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses increased ~~$8.7~~$2.7 million, or ~~1.5~~0.5 percent, for the second quarter of ~~2015~~2016 and ~~$34.4~~decreased $5.7 million, or ~~3.0~~0.5 percent, for the six months ended June 30, 2016 compared with the same periods in 2015. The year-to-date ~~increase in O&M is primarily~~decrease was mainly due to the timing and scope of ~~planned maintenance~~plant outages and ~~overhauls at a number of our generation facilities. We continue to expect that the change in annual O&M expense for 2015 to be within a range of 0 percent to 2 percent, consistent~~discovery work along with ~~our annual guidance assumptions.~~lower nuclear outage and outage amortization costs, which were partially offset by higher gas survey and damage prevention costs.

(Millions of Dollars) Three Months
Ended June 30
2015 vs. 2014 Six Months
Ended June 30
2015 vs. 2014
Plant generation costs $ 5
$ 21
Employee benefits 4
8
Nuclear plant operations (1 ) 3
Other, net 1
2
Total increase in O&M expenses $ 9
$ 34

~~Table of Contents~~

Conservation and DSM Program Expenses — Conservation and DSM program expenses ~~decreased $16.7~~increased $1.8 million, or 3.3 percent, for the second quarter of ~~2015~~2016 and ~~$40.4~~$5.4 million, or 5.0 percent, for the six months ended June 30, 2016 compared with the same periods in 2015. ~~The decreases~~Increases were primarily attributable to ~~lower~~higher electric and natural gas recovery rates at NSP-Minnesota, ~~and~~partially reduced by lower electric recovery rates at PSCo. ~~Lower~~Higher conservation and DSM program expenses are generally offset by ~~lower~~higher revenues.

Depreciation and Amortization — Depreciation and amortization increased ~~$19.3~~$47.9 million, or ~~7.6~~17.5 percent, for the second quarter of ~~2015~~2016 and ~~$46.5~~$94.9 million, or ~~9.3~~17.3 percent, ~~year-to-date.~~for the six months ended June 30, 2016 compared with the same periods in 2015. Increases were primarily ~~attributed~~attributable to ~~normal system expansion~~capital investments, including Pleasant Valley and ~~lower amortization of the excess depreciation reserve~~Border Wind Farms, which were placed into service in ~~Minnesota, partially offset by Minnesota’s amortization of the Department of Energy settlement.~~late 2015.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased ~~$13.5~~$8.7 million, or ~~11.6~~6.7 percent, for the second quarter of ~~2015~~2016 and ~~$25.4~~$17.4 million, or 6.5 percent, for the six months ended June 30, 2016 compared with the same periods in 2015. Increases were due to higher property taxes primarily in Minnesota.

Interest Charges — Interest charges increased $18.8 million, or 13.0 percent, for the second quarter of 2016 and $30.3, or 10.5 percent, for the six months ended June 30, 2016 compared with the same periods in 2015. ~~Increases were due to higher property taxes primarily in Colorado and Minnesota.~~

~~AFUDC, Equity and Debt~~ — AFUDC decreased $14.9 million for the second quarter of 2015 and $27.6 million year-to-date. Decreases were primarily due to the implementation of the CACJA rider on Jan. 1, 2015, facilitating earlier and alternative recovery of construction costs.

~~Interest Charges~~ ~~— Interest charges increased $4.8 million, or 3.5 percent, for the second quarter of 2015 and $10.7 million, or 3.8 percent, for the six months ended June 30, 2015. Increases were primarily due~~The increase was related to higher long-term debt levels, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense ~~increased $5.6~~decreased $5.5 million for the second quarter of ~~2015~~2016 compared with the same period in ~~2014.~~2015. The decrease was primarily due to lower pretax earnings in 2016 and increased wind production tax credits in 2016. The ETR was 34.7 percent for the second quarter of 2016 compared with 35.8 percent for the same period in 2015. The lower ETR in 2016 is primarily due to increased wind production tax credits.

Table of Contents

Income tax expense increased $39.6 million for the first six months of 2016 compared with the same period in 2015. The increase in income tax expense was primarily due to higher pretax earnings in ~~second quarter of 2015, partially offset by decreased permanent plant-related adjustments in 2015 and a tax benefit for an income exclusion in 2014. The ETR was 35.8 percent for~~ the ~~second quarter of 2015 compared with 34.8 percent for the same period in 2014. The higher ETR for 2015 was primarily due to the adjustments referenced above.~~

~~Income tax expense decreased $46.6 million for the first six months of 2015 compared with the same period in 2014. The decrease in income tax expense was primarily due to lower pretax earnings in~~ six months ended June 30, ~~2015,~~2016, partially offset by ~~decreased permanent plant-related adjustments in 2015, the successful resolution of a 2010-2011 IRS audit issue in 2014 and a~~increased wind production tax ~~benefit for an income exclusion in 2014.~~credits. The ETR was ~~35.7~~34.7 percent for the first six months of ~~2015,~~2016 compared ~~to 34.5~~with 35.7 percent for the ~~first six months of 2014~~same period in 2015. The lower ETR in 2016 is primarily due to ~~these adjustments.~~increased wind production tax credits.

Public Utility Regulation ~~and Legislation~~

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 1.1 of Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2014,~~2015 and Public Utility Regulation included in Item 2.2 of Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, ~~2015,~~2016, appropriately represent, in all material respects, the current status of public utility regulation, and are incorporated herein by reference.

NSP-Minnesota

~~Courtenay Wind Farm~~ — NSP-Minnesota plans to move forward with construction and ownership of the Courtenay wind farm, a 200 MW project in North Dakota, pending regulatory approval. In May 2015, NSP-Minnesota filed for expedited regulatory approval in Minnesota and North Dakota. The total construction cost of the project is estimated to be approximately $300 million. On July 30, 2015, the MPUC approved the Courtenay wind purchase with recovery up to $300 million. NDPSC approval of the project is anticipated in August 2015.

~~Table of Contents~~

NSP System Resource Plans— In January 2015, NSP-Minnesota filed its 2016-2030 Integrated Resource Plan (the Plan) with the ~~MPUC, proposing~~MPUC.

Subsequently, NSP-Minnesota proposed revisions to ~~achieve~~the Plan, which addressed stakeholder recommendations as well as the Clean Power Plan (CPP) issued by the EPA. The revised Plan is 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 provisions included in the Plan would allow for a 4060 percent reduction in carbon emissions ~~by 2030~~ from 2005 levels ~~through~~by 2030 and is expected to result in 63 percent of NSP System energy being carbon-free by 2030. NSP-Minnesota believes its Plan provides substantial opportunities for the ~~significant~~ownership of renewable generation and replacement cost generation.

Specific terms of the proposal include:

The addition of renewables, continued commitment to specific critical infrastructure protection annual achievements and the continued operation of its existing cost-effective thermal generation. In March 2015, NSP-Minnesota supplemented the plan to reflect (1) the resource additions that resulted from its Competitive Acquisition Plan (CAP) to meet an identified resource need in the 2018-2020 timeframe, (2) significantly higher than expected response to its Community Solar Gardens program, and (3) additional early Sherco 1 and 2 retirement scenarios. The updated resource plan continues to position NSP-Minnesota to be responsive to future environmental requirements and market trends, builds on the significant investments already made in the NSP System and acknowledges the divergence in state energy policies within the NSP System. Key points of the resource plan include:

~~Adding 600~~800 MW of ~~non-production tax credit~~ wind ~~by 2020~~ and ~~an additional 1,200 MW by 2027, bringing total wind power on the NSP System to over 3,600 MW;~~

~~Adding 187~~400 MW of ~~large-scale~~utility scale solar ~~energy by year-end 2016 and an additional 1,700~~to the pre-2020 time-frame;

The addition of 1000 MW of ~~large-scale solar~~wind and ~~500~~1000 MW of ~~customer-driven small-scale solar; bringing total~~utility scale solar ~~power on~~between 2020-2030;

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

The addition of a 230 MW natural gas combustion turbine in North Dakota by the ~~NSP System to approximately 2,400 MW;~~end of 2025;

~~Operating~~Replacement of Sherco coal generation with a 786 MW natural gas combined cycle unit at the Sherco site no later than 2026; and

Operation of the Monticello and PI nuclear plants through their current ~~licenses;~~license periods in the early 2030’s.

In January 2016, NSP-Minnesota filed supplemental economic and technical information in support of its revised Plan. Additionally, NSP-Minnesota addressed forecasted cost increases at PI (through end of licensed life) and committed to provide additional information if the MPUC wishes to further explore alternatives to operating PI through its current license periods. In July 2016, the DOC submitted its comments, which:

~~Continuing to run~~Concluded NSP-Minnesota’s revised Plan is the most cost-effective after analyzing alternative retirement scenarios for Sherco Units 1 and 2 ~~with gradually decreasing reliance through 2030.~~and a possible retirement of the King plant;

Recommended a separate detailed analysis of early PI retirement;

Recommended no additional solar beyond the community solar gardens program for the first five years; and

Recommended adding up to 1,000 MW of wind by 2019.

~~NSP-Minnesota continues~~The MPUC is expected to ~~execute on several aspects of the additional CAP resources approved by the MPUC in February 2015, including:~~

~~Executed an agreement for 100 MW of distributed solar with Geronimo Energy LLC;~~

~~Executed an agreement with Calpine Corporation for~~make a ~~345 MW expansion at its Mankato Energy Center; and~~

~~Initiated pre-construction tasks needed to construct a 215 MW Black Dog Unit 6 combustion turbine at the existing generation site.~~

~~Since the filing of the resource plan, NSP-Minnesota has completed several stakeholder workshops that provided information~~decision on the Plan and March supplement as well as other key topics of interest to stakeholders. This effort is intended to both focus and reduce formal information requests regarding the resource plan. In July, the Department of Commerce (DOC) filed comments on the Plan recommending that one of the Sherco units be retired in 2025, or alternatively, as early as 2020. A coalition of environmental intervenors filed comments recommending that Sherco Unit 1 close in 2021 and Unit 2 close in 2024. The current schedule calls for NSP-Minnesota to file reply comments on Sept. 2, 2015.late 2016.

~~CapX2020~~ — The estimated cost of the five major CapX2020 transmission projects listed below is $2 billion. NSP-Minnesota and NSP-Wisconsin are responsible for approximately $1.1 billion of the total investment. As of June 30, 2015, Xcel Energy has invested $942.8 million of its $1.1 billion share of the five CapX2020 transmission projects. The projects are as follows:

~~Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 161/345 Kilovolt (KV) transmission line~~ ~~— The project is expected to go into service in the fall of 2016, although segments are being placed in service as they are completed.~~

~~Monticello, Minn. to Fargo, N.D. 345 KV transmission line~~ ~~— In April 2015, the final portion of the project was placed in service.~~

~~Brookings County, S.D. to Hampton, Minn. 345 KV transmission line~~ ~~— The project was placed in service in March 2015.~~

~~Bemidji, Minn. to Grand Rapids, Minn. 230 KV transmission line~~ ~~— The 70-mile Bemidji, Minn. to Grand Rapids, Minn. line was placed in service in September 2012.~~

~~Big Stone South to Brookings County, S.D. 345 KV transmission line~~ ~~— Construction is anticipated to begin in late 2015, with completion in 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. NSP-Minnesota plans to add 287 MW of large-scale solar to its system by the end of 2016. NSP-Minnesota also offers small solar programs: 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 incentive program for small solar using products made in-state, which generates renewable energy credits for utilities including NSP-Minnesota.

~~Table of Contents~~

During 2015, NSP-Minnesota sought policy guidance from the MPUC regarding the price and size of Solar*Rewards Community projects. The program was intended for projects one MW or less. Many proposals, however, were sized between 10 and 50 MW. In June 2015, the MPUC reviewed the Solar*Rewards Community program and voted to limit the size of solar installations eligible to participate in the program, more closely aligning the program with its original intent. The MPUC decision limits projects to five MW or less through Sept. 25, 2015. Subsequently, projects must be one MW or less.

~~Minnesota Legislation~~ — In June 2015, the Minnesota governor signed the Jobs and Energy bill into law. Several approved mechanisms may provide additional options and opportunities in future rate cases, including the duration of future multi-year plans and more certainty regarding recovery of costs and the impact to customers. This bill provides:

~~Increased flexibility for utilities to submit a multi-year plan (MYP) of up to five years;~~

~~The potential for full capital recovery for all proposed years;~~

~~O&M cost recovery based on an index;~~

~~Distribution costs that facilitate grid modernization are eligible for rider recovery;~~

~~Natural gas extension costs for unserved areas can be socialized and are eligible for rider recovery;~~

~~Recovery of plant closure costs, should the MPUC order early plant closure; and~~

~~Allows implementation of interim rates for the first and second years of the MYP.~~

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, ~~2014~~2015 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 and Nuclear Power Operations included in Item 2 of Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2016, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated herein by reference.

~~Nuclear Regulatory Performance~~— The NRC has a Reactor Oversight Process that classifies U.S. nuclear reactors into various categories (referred to as Columns, from 1 to 5). Such issues are evaluated as either green, white, yellow, or red based on their safety significance, with green representing the least safety concern and red representing the most concern.

At Dec. 31, 2014, PI Units 1 and 2 were in Column 1 (licensee response) with all green performance indicators and no greater than green findings or violations. Monticello was in Column 3 (degraded cornerstone) with all green performance indicators, a yellow finding related to flood control and a potentially greater than green finding related to plant security. The NRC informed Xcel Energy in February 2015 that the final determination on the security finding was greater than green. In March 2015, Monticello was upgraded from Column 3 (degraded cornerstone) to Column 2 (regulatory response), based on the results of an NRC inspection in late 2014 to close out the flood control finding. Monticello will remain in Column 2 until the NRC performs an inspection and confirms that the white security finding can be closed. Upon closure of the white security finding, Monticello will be eligible to be upgraded to Column 1. Plants in Column 1 are subject to only a pre-defined set of basic NRC inspections. The NRC conducted an inspection on the security finding in late July 2015, the results of which are pending.

~~NSP-Wisconsin~~

~~NSP-Wisconsin / American Transmission Company, LLC (ATC) - La Crosse, Wis. to Madison, Wis. Transmission Line~~ — In October 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 KV transmission line that would extend from La Crosse, Wis. to Madison, Wis. NSP-Wisconsin’s half of the line will be shared with three partners, Dairyland Power Cooperative, WPPI Energy and Southern Minnesota Municipal Power Association-Wisconsin. In 2011, MISO determined the line to be a MVP project, and as such, eligible for cost sharing under MISO’s MVP tariff.

In April 2015, the PSCW issued its order approving a CPCN and route for the project. In June 2015, the PSCW denied two requests for rehearing. Two groups have appealed the CPCN Order to county court. Court action is pending and 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 will cost approximately $580 million. NSP-Wisconsin’s portion of the investment is estimated to be approximately $207 million. NSP-Wisconsin and ATC anticipate beginning construction on the line in mid-2016, with completion by late 2018.

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NSP-Wisconsin

2015 Electric Fuel Cost Recovery — NSP-Wisconsin’s electric fuel costs for the year ended Dec. 31, 2015 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 load as a result of mild weather, lower natural gas prices and lower purchased power prices in the MISO market. NSP-Wisconsin recorded a deferral of approximately $9.2 million through Dec. 31, 2015. In July 2016, the PSCW required NSP-Wisconsin to provide a direct refund of $9.5 million to customers. Accordingly, NSP-Wisconsin plans to apply the refund to customer bills based on usage in September 2016.

2016 Electric Fuel Cost Recovery — NSP-Wisconsin’s electric fuel costs for the six months ended June 30, 2016 were lower than authorized in rates and outside the two percent annual tolerance band established in the Wisconsin fuel cost recovery rules, primarily due to lower sales volume and lower purchased power costs coupled with moderate weather. Under the fuel cost recovery rules, NSP-Wisconsin may retain the amount of over-recovery up to two percent of authorized annual fuel costs, or approximately $3.5 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 $3.3 million through June 30, 2016. 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, NSP-Wisconsin will file a reconciliation of 2016 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.

PSCo

~~Boulder, Colo. Municipalization~~Colorado 2017 Electric Resource Plan — In May 2016, PSCo filed its 2017 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 ~~franchise agreement~~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 first phase of the Electric Resource Plan is anticipated to conclude in the second quarter of 2017 with the ~~City~~second phase to begin shortly after.

Brush to Castle Pines 345 Kilovolt (KV) Transmission Line — In April 2015, the CPUC granted a certificate of ~~Boulder (Boulder) expired~~public convenience and necessity (CPCN) to construct a new 345 KV transmission line originating from Pawnee generating station, near Brush, CO to the Daniels Park substation, near Castle Pines, CO to be placed in ~~December 2010. In November 2011, a ballot measure was passed which authorized the formation and operation of a municipal utility and the issuance of enterprise revenue bonds, subject~~service by May 2022. The estimated project cost is $178.3 million. The CPUC’s decision requires that project construction begin no earlier than May 2020 to ~~certain restrictions, including the level of initial rates and debt service coverage. In May 2014, the Boulder City Council passed an ordinance to establish an electric utility.~~meet resource needs by 2023.

In 2013, the CPUC ruled that it has jurisdiction under Colorado law to determine the utility that will serve customers outside Boulder’s city limits, and will determine certain system separation matters as well as what facilities need to be constructed to ensure reliable service. The CPUC has declared that it should make its determinations prior to any eminent domain actions. In January 2014, Boulder appealed this ruling to the Boulder District Court. In January 2015, the Boulder District Court affirmed the CPUC decision.

Boulder sent PSCo an offer of $128 million for certain portions of PSCo’s transmission and distribution business. PSCo has notified Boulder that its offer was deficient. Under Colorado law, a condemning entity must pay the owner fair market value for the taking of and damages to the remainder of the property.

In July 2014, Boulder filed a petition for condemnation in the Boulder District Court. PSCo filed a motion to dismiss the petition based upon the CPUC’s ruling that it must determine the appropriate system separations prior to Boulder filing its condemnation case. PSCo’s motion to dismiss was granted in February 2015. This decision does not prevent Boulder from filing another condemnation petition if it obtains CPUC approval of its separation plan.

~~In August 2014,~~April 2016, PSCo filed a petition with the ~~FERC requesting an order requiring~~CPUC to request that Boulder’s attempt to acquire PSCo’s transmission and distribution facilities by condemnation requires prior FERC approval under the Federal Power Act. In December 2014, the FERC issued an order granting PSCo’s petition.

~~If Boulder proceeds with another condemnation petition and were to succeed in the eminent domain proceeding, PSCo would seek to obtain full compensation~~construction begin as early as February 2017 for the ~~business and its associated property taken~~project to be placed in service by ~~Boulder, as well as for all damages resulting~~October 2019. This project was proposed to ~~PSCo and its system. PSCo would also seek appropriate compensation for stranded costs~~support the interconnection of new generation at PSCo’s Pawnee or Missile Site substations. As the Rush Creek Wind Project interconnects at the Missile Site substation, parties have requested that PSCo’s petition to start construction in 2017 be consolidated with the ~~FERC.~~

~~In April 2015, Boulder issued a request for proposal for a partial requirements wholesale electric power supply agreement. Boulder indicated that~~Rush Creek Wind Project. The CPUC granted the request for ~~proposal was designed to elicit~~consolidation and a ~~wholesale power supply arrangement for a five-year term commencing~~decision on ~~Jan. 1, 2018. Boulder has requested that PSCo consider different pricing structures and allow for Boulder to reduce demand over~~ the ~~term of the contract.~~petition is expected by November 2016.

Rush Creek Wind Ownership Proposal — In May ~~2015,~~2016, PSCo ~~sent Boulder a letter indicating its willingness to discuss a power supply arrangement with Boulder, but no formal offer was made. On July 7, 2015, Boulder~~ filed an application ~~with the CPUC requesting~~to build, own and operate a 600 MW wind generation facility at a cost of approximately $1 billion, including transmission investment. PSCo requested approval of ~~Boulder’s proposed separation plan.~~

~~Steam System Package Boilers~~the proposal by November 2016, in order to commence the project timely and ~~Regulatory Plan~~— ~~In December 2014, PSCo filed~~capture the ~~results of a steam survey along with both a short-term plan and a long-term plan~~full production tax credit benefit for the steam system consisting of a request for a conditional CPCN to construct either one or two boilers for its steam utility, dependent on the next two seasons of winter peaking capacity. In April 2015, the CPUC approved a settlement agreement between PSCo and all parties, which resolved all issues.customers.

~~Cabin Creek Hydro Upgrade~~ — Colorado legislation allows for utilities to own up to 50 percent of new renewable resources without a competitive bidding process if projects can be developed at a reasonable price and demonstrate economic benefit.

PSCo ~~filed~~believes its proposed facility can be constructed at a ~~CPCN with~~reasonable cost compared to the cost of similar renewable resources available on the market, and that it will be able to demonstrate to the CPUC and the independent evaluator that the proposed wind project meets the reasonable price and economic benefit standards. If approved by the CPUC, the new facility is projected to go into service in May 2015 to upgrade the Cabin Creek Hydro facility. The upgrade is estimated to cost $89.2 million and will extend the life of the facility by 40 years as well as increase the maximum output by 36 MW. A final CPUC decision is expected in the fourth quarter of 2015.December 2018.

~~SPS~~

~~Texas Legislation~~ ~~— In June 2015,~~ the Texas Governor signed HB 1535 into law. As a result, SPS may reduce regulatory lag through earlier inclusion of certain capital additions in rate base, as well as expediting the implementation of new rates. Key provisions of the bill are as follows:

~~Utilities may include actual and estimated post-test year capital additions up through 30-days before the filing date;~~

~~A new natural gas generating unit may be included in rate base as long as it is in service before the proposed effective rate date;~~

~~Rates will go into effect 155 days after filing (previously it was 185 days). If the case is not final by this date, then a utility can go back and surcharge; and~~

~~Establishes time limits for the PUCT to rule on a new generation plant request for a certificate of convenience and necessity.~~

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Intervenors responded to PSCo’s application and answer testimony was filed in July 2016. The next steps in the procedural schedule are as follows:

PSCo’s rebuttal testimony — Aug. 22, 2016; and

Hearings — Sept. 7-9, 2016.

Natural Gas Reserves Investments — In January 2016, PSCo filed a request with the CPUC for approval of a long-term natural gas procurement and price hedging framework. In June 2016, PSCo withdrew its application as it concluded that the litigation of the application would be contentious and, as structured, the framework would not address many of the concerns raised about the program by various intervenors. PSCo will continue to examine opportunities to mitigate price volatility for its customers.

Joint Dispatch Agreement (JDA) — In February 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 sell its excess generation to other JDA counterparties. Margins on these sales would be shared among PSCo and its customers, of which 10 percent would be retained by PSCo. 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. Operations under the JDA are expected to begin in August 2016.

Advanced Grid Intelligence and Security —In August 2016, PSCo filed a request with the CPUC to approve a certificate of public convenience and necessity (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. These major projects are expected to improve customer experience, enhance grid reliability and enable the implementation of new and innovative programs and rate structures. The estimated capital investment for the project is approximately $500 million, which is largely included in Xcel Energy’s base capital forecast for 2016-2020. The project would be completed by 2021.

Decoupling Filing — On July 12, 2016, PSCo filed a request with the CPUC to approve a partial decoupling mechanism for a five year period, effective in 2017. The proposed decoupling adjustment would allow PSCo to adjust annual revenues based on changes in weather normalized average use per customer for the residential and small C&I 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.

SPS

TUCO Substation to Yoakum County Substation to Hobbs Plant Substation 345 KV Transmission Line— In June 2015, SPS filed a certificate of convenience and necessity (CCN) with the PUCT for the Yoakum County to Texas/New Mexico State line portion of this 345 KV line project. The PUCT approved this CCN in March 2016. CCNs for the TUCO to Yoakum County substation segment were filed in June 2016. CCNs for the Texas/New Mexico state line to Hobbs Plant segment are planned to be filed in the second half of 2016. The estimated project cost is $242 million. This line is scheduled to be in service in 2019.

Hobbs Plant Substation to China Draw Substation 345 KV Transmission Line — In May 2016, SPS filed a CCN with the NMPRC for the Hobbs Plant to China Draw transmission line. The estimated project cost is approximately $163 million. The line is anticipated to be in service in 2018.

Wholesale Customer Participation in 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. 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 revenue requirement would be spread across a smaller base of customers. SPS intends to participate in the PUCT’s proceeding to protect its customers’ interests. LP&L has stated that it intends to file an application with the PUCT for a CCN for approval of the transfer by late 2016.

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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. The PUCT has stated it intends to discuss, and possibly decide, issues regarding procedures, timing, scope of proceedings and types of analyses in August 2016.

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 June 2016, LP&L and Golden Spread Electric Cooperative, Inc. (Golden Spread) protested SPS’ filing. LP&L argued that SPS has no legal authority to impose a charge and LP&L’s departure would reduce certain costs to SPS and asked the FERC to reject the filing. Golden Spread asked FERC to clarify that if the exit fee is not approved, remaining wholesale transmission customers could challenge future recovery of SPS’ costs. Additionally, the PUCT asked FERC to hold the filing in abeyance pending the outcome of the PUCT proceedings evaluating the LP&L proposal. SPS requested FERC to act on the matter by mid-September 2016.

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. The DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) recently 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 recently commented on the proposed rules and 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 2016.

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 PSIA and GUIC riders, respectively.

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, ~~2014.~~2015 and Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2016. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Order, New ROE Policy — ~~In June 2014, the~~The FERC has adopted a new two-step ROE methodology for electric utilities. The issue of how to apply the new FERC ROE methodology is being contested in various complaint proceedings. Two complaints against the MISO TOs, including NSP-Minnesota and NSP-Wisconsin, are pending FERC action after issuance of initial decisions by ALJs in December 2015 and June 2016, respectively. FERC is not expected to issue orders in any of ~~these~~the litigated ROE complaint proceedings until ~~2016.~~later in 2016 or 2017. See Note 5 to the consolidated financial statements for discussion of the ~~SPS Wholesale Rate and~~ MISO ROE ~~complaints.~~Complaints.

SPS Asset Transfer to Xcel Energy Southwest Transmission Company, LLC (XEST) — In 2015 through early 2016, SPS submitted filings to the FERC, PUCT, NMPRC and Kansas Corporation Commission (KCC) seeking approval to transfer ownership of SPS’ 345 KV transmission assets in Kansas and Oklahoma to XEST at net book value of approximately $103 million.

In June 2016, SPS and XEST made filings to withdraw the pending PUCT, NMPRC, KCC and FERC applications due to the relatively slow pace of Order 1000 competitive transmission development projects in the SPP. All withdrawal requests have been granted, and the matters are now closed.

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Formula Rate Treatment of Accumulated Deferred Income Taxes (ADIT) — In 2015, the MISO TOs, including NSP-Minnesota and NSP-Wisconsin, SPS and PSCo filed separate changes to their transmission formula rates and the PSCo production formula rate to modify the treatment of ADIT to comply with IRS guidance regarding how ADIT must be reflected in formula rates using future test years and a true-up. 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.

Golden Spread protested the proposed changes to the SPS transmission formula rate. In December 2015, the FERC partially accepted the proposed NSP-Minnesota and NSP-Wisconsin transmission formula rate changes, but rejected the changes regarding the treatment of ADIT in the formula rate true-up. NSP-Minnesota and NSP-Wisconsin sought clarification or rehearing of the FERC order partially rejecting the NSP System filing. In April 2016, FERC accepted the SPS and PSCo formula rate changes, subject to a compliance filing. SPS and PSCo submitted the compliance filings in May 2016. FERC action on the NSP-Minnesota and NSP-Wisconsin request for clarification remains pending.

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.

Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. Xcel Energy’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

At June 30, ~~2015,~~2016, 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	$	3,255	$	7,932	$	1,272	$	715	$	13,174	1	$	2,378	$	6,871	$	1,204	$	101	$	10,554
NSP-Minnesota	2	5,812		—		—		—		5,812
PSCo	1	2		—		—		—		2		1	332		47		—		—		379
		$	9,069	$	7,932	$	1,272	$	715	$	18,988		$	2,710	$	6,918	$	1,204	$	101	$	10,933

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	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	$	260	$	—	$	—	$	—	$	260	2	$	(839	)	$	—	$	—	$	—	$	(839	)

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

2 — Prices based on models and other valuation methods.

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


	Six Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2015			2014			2016			2015
Fair value of commodity trading net contract assets outstanding at Jan. 1	$	21,811		$	30,514		$	11,040		$	21,811
Contracts realized or settled during the period	3,472			(7,278		)	(1,406		)	3,472
Commodity trading contract additions and changes during period	(6,035		)	3,700			460			(6,035		)
Fair value of commodity trading net contract assets outstanding at June 30	$	19,248		$	26,936		$	10,094		$	19,248

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. At June 30, 2015, a 10 percent increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $0.4 million, whereas a 10 percent decrease would decrease pretax income from continuing operations by approximately $0.4 million. At June 30, 2014, a 10 percent increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $1.1 million, whereas a 10 percent decrease would decrease pretax income from continuing operations by approximately $1.1 million.

Xcel Energy Inc.’s utility subsidiaries’ wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, 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 June 30		VaR Limit		Average		High		Low		Three Months Ended June 30		VaR Limit		Average		High		Low
2016											$	0.22	$	3.00	$	0.22	$	0.38	$	0.06
2015	$	0.47	$	3.00	$	0.23	$	1.30	$	0.06	0.47		3.00		0.23		1.30		0.06
2014	0.42		3.00		0.77		1.69		0.06

Nuclear Fuel Supply — NSP-Minnesota is scheduled to take delivery of approximately 87 percent of its 2016 and approximately 13 percent of its ~~2015~~2017 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 3436 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 beyond 2015.~~material.

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

At June 30, ~~2015~~2016 and ~~2014,~~2015, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately ~~$4.5~~$5.9 million and ~~$7.8~~$4.5 million, respectively. See Note 8 to the consolidated financial statements for a discussion of Xcel Energy Inc. and its subsidiaries’ interest rate derivatives.

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NSP-Minnesota also maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. At June 30, ~~2015,~~2016, 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 do not have an impact on earnings.

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

At June 30, 2016, a 10 percent increase in commodity prices would have resulted in a decrease in credit exposure of $9.2 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $16.4 million. At June 30, 2015, a 10 percent increase in commodity prices would have resulted in a decrease in credit exposure of $3.4 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $4.5 million. At June 30, 2014, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $35.9 million, while a decrease in prices of 10 percent would have resulted in a decrease in credit exposure of $22.2 million.

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

Fair Value Measurements

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

Commodity Derivatives — Xcel Energy continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at June 30, ~~2015.~~2016. Xcel Energy also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at June 30, ~~2015.~~2016.

Commodity derivative assets and liabilities assigned to Level 3 typically consist of FTRs, as well as forwards and options that are long-term in nature. Level 3 commodity derivative assets and liabilities represent ~~3.2~~1.5 percent and ~~34.8~~8.5 percent of total assets and liabilities, respectively, measured at fair value at June 30, ~~2015.~~2016.

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 ~~$59.3~~$28.1 million and ~~$12.5~~$3.6 million of estimated fair values, respectively, for FTRs held at June 30, ~~2015.~~2016.

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 immaterial Level 3 commodity ~~derivative assets included no assets~~forwards and ~~no liabilities, for forwards held at June 30, 2015. There were no Level 3~~ options held at June 30, ~~2015.~~2016.

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~~Nuclear Decommissioning Fund~~ — Nuclear decommissioning fund assets assigned to Level 3 consist of private equity investments and real estate investments. Based on an evaluation of NSP-Minnesota’s ability to redeem private equity investments and real estate investment funds measured at net asset value, estimated fair values for these investments totaling $204.8 million in the nuclear decommissioning fund at June 30, 2015 (approximately 11.1 percent of total assets measured at fair value) are assigned to Level 3. Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a regulatory asset.

Liquidity and Capital Resources

Cash Flows


	Six Months Ended June 30				Six Months Ended June 30
(Millions of Dollars)	2015		2014		2016		2015
Cash provided by operating activities	$	1,509	$	1,040	$	1,413	$	1,509

Net cash provided by operating activities ~~increased $469~~decreased $96 million for the six months ended June 30, ~~2015~~2016 compared with the six months ended June 30, ~~2014.~~2015. The ~~increase~~decrease was primarily due to ~~changes in working capital, including income tax~~timing of customer receipts, refunds ~~received in 2015 compared to taxes paid in 2014, changes in regulatory assets~~ and ~~liabilities~~recovery on 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, deferred tax expenses and a charge related to the Monticello LCM/EPU ~~project)~~project in 2015).


	Six Months Ended June 30						Six Months Ended June 30
(Millions of Dollars)	2015			2014			2016			2015
Cash used in investing activities	$	(1,431	)	$	(1,531	)	$	(1,443	)	$	(1,431	)

Net cash used in investing activities ~~decreased $100~~increased $12 million for the six months ended June 30, ~~2015~~2016 compared with the six months ended June 30, ~~2014.~~2015. The ~~decrease~~increase was primarily attributable to ~~higher capital expenditures~~the establishment of rabbi trusts in ~~2014 related to CACJA projects~~2016 and the impact of higher insurance proceeds received in 2015, partially offset by higher payments for capital expenditures in 2015 related to ~~Sherco Unit 3.~~the completion of certain generation and transmission projects.


	Six Months Ended June 30					Six Months Ended June 30
(Millions of Dollars)	2015			2014		2016		2015
Cash (used in) provided by financing activities	$	(22	)	$	484
Cash provided by (used in) financing activities						$	23	$	(22	)

Net cash provided by financing activities was $23 million for the six months ended June 30, 2016 compared with net cash used in financing activities ~~was~~of $22 million for the six months ended June 30, 2015, ~~compared with net cash provided by financing activities of $484 million for the six months ended June 30, 2014,~~ or a change of ~~$506~~$45 million. The difference was primarily due to higher debt issuances and lower repayments of short-term debt, ~~in 2015 compared to proceeds in 2014 and less issued common stock,~~ partially offset by ~~a repayment~~repayments of long-term debt and higher dividend payments in ~~2014.~~2016.

Capital Requirements

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

Regulation of Derivatives — In July 2010, financial reform legislation was passed that provides for the regulation of derivative transactions amongst other provisions. Provisions within the bill provide the Commodity Futures Trading Commission (CFTC) and the SEC with expanded regulatory authority over derivative and swap transactions. Regulations effected under this legislation could preclude or impede some types of over-the-counter energy commodity transactions and/or require clearing through regulated central counterparties, which could negatively impact the market for these transactions or result in extensive margin and fee requirements.

~~As a result of this legislation, there will be material increased reporting requirements for certain volumes of derivative and swap activity. In April 2012, the~~The CFTC ruled that swap dealing activity conducted by entities for the preceding 12 months under a notional limit, initially set at $8 billion, ~~with further potential reduction to $3 billion after five years,~~ will fall under the general de minimis threshold and will not subject an entity to registering as a swap dealer. An entity may deal in utility operations-related swaps and not be required to register as a swap dealer provided that the aggregate gross notional amount of swap dealing activity (including utility operations-related swaps) does not exceed the generalThe de minimis threshold ~~and provided that the entity has not exceeded the special entity de minimis threshold (excluding utility operations-related swaps) of $25 million for the preceding 12 months.~~is scheduled to be reduced to $3 billion in 2017. Xcel Energy’s current and projected swap activity is well below these de minimis thresholds. The bill also contains provisions that ~~should~~ exempt certain derivatives end users from much of the clearing and margin ~~requirements.~~requirements and Xcel ~~Energy does not expect to be materially impacted by~~Energy’s Board of Directors has renewed the ~~margining provisions.~~end-user exemption on an annual basis. Xcel Energy is currently meeting all ~~other~~ reporting ~~requirements.~~

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~~SPP FTR Margining Requirements~~ — The SPP conducted its first annual FTR auction in the spring of 2014 associated with the implementation of the SPP Integrated Market. The process for transmission owners involves the receipt of Auction Revenue Rights (ARRs)requirements and if elected by the transmission owner, conversion of those ARRs to firm FTRs. SPP requires that the transmission owner post collateral for the conversion of ARRs to FTRs. At June 30, 2015, SPS had a $36 million letter of credit posted with SPP, which was a reduction from the initial requirement of $41 million.transaction restrictions.

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 ~~2015,~~2016, contributions of ~~$90.0~~$125.0 million were made across four of Xcel Energy’s pension plans;

In ~~2014,~~2015, contributions of ~~$130.6~~$90.0 million were made across four of Xcel Energy’s pension plans; and

For future years, we anticipate contributions will be made as necessary.

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Capital Sources

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

Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts. At June 30, ~~2015,~~2016, approximately ~~$20.4~~$9.1 million of cash was held in these accounts.

Amended Credit ~~Facilities —~~Agreements - In June 2016, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS ~~and Xcel Energy Inc. each have~~entered into amended five-year credit agreements with a syndicate of banks. The total ~~size~~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 of the lines of credit, ~~facilities is $2.75 billion and each~~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 ~~facility terminates in October 2019.~~ratings.

~~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.

Credit Facilities —As of July ~~27, 2015,~~25, 2016, 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	$	60	$	940	$	—	$	940	$	1,000	$	401	$	599	$	—	$	599
PSCo	700		35		665		1		666		700		98		602		1		603
NSP-Minnesota	500		184		316		1		317		500		18		482		1		483
SPS	400		257		143		1		144		400		95		305		1		306
NSP-Wisconsin	150		—		150		5		155		150		23		127		—		127
Total	$	2,750	$	536	$	2,214	$	8	$	2,222	$	2,750	$	635	$	2,115	$	3	$	2,118


^(a)	These credit facilities expire in ~~October 2019.~~June 2021.


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

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.

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Commercial paper outstanding for Xcel Energy was as follows:


(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2015			Twelve Months Ended Dec. 31, 2014			Three Months Ended June 30, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	2,750		$	2,750		$	2,750		$	2,750
Amount outstanding at period end	451			1,020			447			846
Average amount outstanding	780			841			404			601
Maximum amount outstanding	1,072			1,200			841			1,360
Weighted average interest rate, computed on a daily basis	0.48		%	0.33		%	0.72		%	0.48		%
Weighted average interest rate at period end	0.48			0.56			0.80			0.82

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Money Pool — Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. The money pool balances are eliminated in consolidation.

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

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

~~During 2015,~~ Xcel Energy Inc.’s and its utility ~~subsidiaries completed~~subsidiaries’ 2016 financing plans reflect the ~~following bond issuances:~~following:

In ~~May, PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025;~~

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

In June, ~~NSP-Wisconsin~~PSCo issued ~~$100~~$250 million of ~~3.3~~3.55 percent first mortgage bonds due June 15, ~~2024.~~

~~During 2015, Xcel Energy Inc. and its utility subsidiaries anticipate issuing the following:~~

~~NSP-Minnesota plans to issue approximately $600 million of first mortgage bonds;~~2046; and

SPS plans to issue approximately ~~$200~~$300 million of first mortgage ~~bonds.~~bonds in the third quarter.

~~Xcel Energy does not anticipate issuing any additional equity, beyond its dividend reinvestment program and benefit programs, for 2015-2019, based on its current capital expenditure plan.~~ 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.

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Earnings Guidance

Xcel Energy’s ~~2015~~2016 ongoing earnings guidance is ~~$2.00~~$2.12 to ~~$2.15~~$2.27 per share. Key assumptions related to ~~2015~~2016 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~~decrease by approximately 0.5 percent.

~~Weather-normalized~~Weather normalized retail firm natural gas sales are projected to ~~decline approximately 2 percent.~~be relatively flat.

Capital rider revenue is projected to increase by ~~$155~~$40 million to ~~$165~~$50 million over ~~2014~~2015 levels.

The change in O&M expenses is projected to be within a range of 0 percent to 21 percent from ~~2014~~2015 levels.

Depreciation expense is projected to increase ~~$130 million to $150~~approximately $200 million over ~~2014~~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 ~~$60~~$40 million to ~~$70~~$50 million over ~~2014~~2015 levels.

Interest expense (net of AFUDC — debt) is projected to increase $40 million to $50 million over ~~2014~~2015 levels.

AFUDC — equity is projected to ~~decline~~increase approximately ~~$30~~$0 million to ~~$40~~$10 million from ~~2014~~2015 levels.

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

Average common stock and equivalents are projected to be approximately ~~508~~509 million shares.

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 ~~weather-normalized,~~ ongoing ~~2014~~2015 EPS of ~~$2.00;~~$2.10, which was the mid-point of Xcel Energy’s 2015 ongoing guidance range;

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.

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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 June 30, ~~2015,~~2016, 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 2016, Xcel Energy implemented the general ledger 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 additional modules and expects to begin conversion of existing work management systems to this new ERP system. In connection with this ongoing implementation, Xcel Energy has updated and will continue updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting procedures. Xcel Energy does not expect the implementation of the additional modules to materially affect its internal control over financial reporting.

No ~~change~~changes in Xcel Energy’s internal control over financial reporting ~~has~~ occurred during the most recent fiscal quarter that ~~has~~ materially affected, or isare 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 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, ~~2014,~~2015, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table provides information about our purchases of equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Exchange Act for the quarter ended June 30, ~~2015:~~2016:

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

April 1, ~~2015~~2016 — April 30, ~~2015~~2016

—

May 1, ~~2015~~2016 — May 31, ~~2015~~2016

—

June 1, ~~2015~~2016 — June 30, ~~2015~~2016

—

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, 2012 (Exhibit 3.01 to Form 8-K dated May 16, 2012 (file no. 001-03034)).
3.02*	~~Restated By-Laws of~~ Xcel Energy Inc. Bylaws, as amended on Feb. 17, 2016 (Exhibit 3.01 to Form 8-K dated ~~Aug. 12, 2008~~Feb. 17, 2016 (file no. 001-03034)).
4.01*	Supplemental Trust Indenture ~~No. 8~~ dated as of ~~June~~May 1, ~~2015~~2016 between ~~Xcel Energy Inc.~~NSP-Minnesota and ~~Wells Fargo~~The Bank ~~National Association,~~of New York Mellon Trust Company, N.A., as successor Trustee, creating ~~$250,000,000 aggregate~~$350,000,000 principal amount of ~~1.20% Senior Notes,~~3.600 percent First Mortgage Bonds, Series due ~~June 1, 2017 and $250,000,000 aggregate principal amount of 3.30% Senior Notes, Series due June 1, 2025.~~May 15, 2046. (Exhibit 4.01 to Form 8-K of NSP-Minnesota dated ~~June 1, 2015~~May 31, 2016 (file no. ~~001-03034)~~001-31387)).
4.02*	Supplemental Indenture dated as of ~~May~~June 1, ~~2015~~2016 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250,000,000 principal amount of ~~2.90%~~3.55 percent First Mortgage Bonds, Series No. 2829 due ~~2025.~~2046. (Exhibit 4.01 to Form 8-K of PSCo dated ~~May 12, 2015~~June 13, 2016 (file no. 001-03280)).
10.01+	Fifth Amendment dated May 3, 2016 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy.
10.02*	Second Amended and Restated Credit Agreement, dated as of June 20, 2016 among Xcel Energy Inc., as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.01 to Form 8-K of Xcel Energy dated June 20, 2016 (file no. 001-03034)).
10.03*	Second Amended and Restated Credit Agreement, dated as of June 20, 2016 among NSP-Minnesota, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.02 to Form 8-K of Xcel Energy dated June 20, 2016 (file no. 001-03034)).
10.04*	Second Amended and Restated Credit Agreement, dated as of June 20, 2016 among PSCo, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.03 to Form 8-K of Xcel Energy dated June 20, 2016 (file no. 001-03034)).
10.05*	Second Amended and Restated Credit Agreement, dated as of June 20, 2016 among SPS, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.04 to Form 8-K of Xcel Energy dated June 20, 2016 (file no. 001-03034)).
10.06*	Second Amended and Restated Credit Agreement, dated as of June 20, 2016 among NSP-Wisconsin, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.05 to Form 8-K of Xcel Energy dated June 20, 2016 (file no. 001-03034)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, ~~2015~~2016 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.

~~July 31, 2015~~Aug. 4, 2016	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)

		/s/ ~~TERESA S. MADDEN~~ROBERT C. FRENZEL
		~~Teresa S. Madden~~Robert C. Frenzel
		Executive Vice President, Chief Financial Officer
		(Principal Financial Officer)

6257



2014 Rate Request (Millions of Dollars)	NSP-Minnesota			MPUC May Decision
NSP-Minnesota’s filed rate request	$	192.7		$	192.7
Sales forecast (with true-up to 12 months of actual weather-normalized sales)	(38.5		)	(37.5		)
ROE	—			(31.9		)
Monticello EPU cost recovery	(12.2		)	(37.6		)
Property taxes (with true-up to actual 2014 accruals)	(13.2		)	(13.2		)
Prairie Island EPU cost recovery	(5.1		)	(5.0		)
Health care, pension and other benefits	(1.9		)	(3.1		)
Other, net	(6.5		)	(5.5		)
Total 2014	$	115.3		$	58.9



2015 Rate Request (Millions of Dollars)	NSP-Minnesota			MPUC May Decision
NSP-Minnesota’s filed rate request	$	98.5		$	98.5
Monticello EPU cost recovery	11.7			35.4
Depreciation / Retirements	—			(0.5		)
Property taxes	(3.3		)	(3.3		)
Production tax credits to be included in base rates	(11.1		)	(11.1		)
U.S. Department of Energy (DOE) settlement proceeds	10.1			10.1
Emission chemicals	(1.6		)	(1.6		)
Other, net	1.7			(2.3		)
Total 2015 step increase - prior to Monticello Life Cycle Management (LCM)/EPU cost disallowance	$	106.0		$	125.2

Total for 2014 and 2015 step increase - prior to Monticello LCM/EPU cost disallowance	$	221.3		$	184.1
Monticello LCM/EPU cost disallowance	—			(18.0		)
Total for 2014 and 2015 step increase - including Monticello LCM/EPU cost disallowance	$	221.3		$	166.1



(Millions of Dollars)	MPUC July Decision
2015 annual rate increase - based on MPUC May order	$	166.1
Reconsideration/clarification adjustments:
2015 Monticello EPU used-and-useful adjustment	(13.8		)
2014 property tax final true-up	(3.1		)
Other, net	0.2
Total 2015 annual rate increase	$	149.4
Impact of interim rate effective March 3, 2015	(3.6		)
Estimated 2015 revenue impact	$	145.8



(Millions of Dollars)	2015			2016 Step		2017 Step
Total base rate increase	$	40.5		$	7.6	$	18.1
Incremental PSIA rider revenues	(0.1		)	21.7		21.2
Total revenue impact	$	40.4		$	29.3	$	39.3



(Millions of Dollars)	Staff			OCC
PSCo’s filed 2015 base rate request	$	40.5		$	40.5
ROE	(12.8		)	(13.7		)
Capital structure and cost of debt	(12.8		)	(4.8		)
Cherokee pipeline adjustment	(11.2		)	4.8
Move to 2014 historical test year	(10.5		)	(16.4		)
O&M expenses	(3.5		)	(2.7		)
Other, net	(4.4		)	(1.9		)
Total adjustments	$	(55.2	)	$	(34.7	)

Recommended (decrease) increase	$	(14.7	)	$	5.8



										SPS Rebuttal Testimony
(Millions of Dollars)	AXM			OPUC			Staff			SPS Rebuttal Testimony
SPS’ revised rate request	$	58.9		$	58.9		$	58.9		$	58.9
Investment for capital expenditures — post-test year adjustments	(11.3		)	(23.8		)	(23.8		)	—
Lower ROE	(10.9		)	(13.5		)	(12.1		)	—
Rate base adjustments (largely the removal of the prepaid pension asset)	(6.2		)	(6.8		)	—			—
O&M expense adjustments	(13.7		)	(11.0		)	(7.9		)	(1.6		)
Depreciation expense	(13.3		)	—			—			—
Property taxes	—			(1.2		)	(4.4		)	(1.8		)
Revenue adjustments	(2.2		)	(0.2		)	—			—
Wholesale load reductions	(13.2		)	—			(11.1		)	—
Southwest Power Pool (SPP) transmission expansion plan	—			—			—			(7.3		)
Other, net	(1.7		)	(0.6		)	(2.2		)	(1.8		)
Total recommendation	$	(13.6	)	$	1.8		$	(2.6	)	$	46.4
Adjustment to move rate case expenses to a separate docket	—			—			—			(4.3		)
Recommendation, excluding rate case expenses	$	(13.6	)	$	1.8		$	(2.6	)	$	42.1



	Refund Period		Production ROE		Transmission ROE ^(a)
Golden Spread ^(b)	1		8.78	%	9.28	%
	2		8.51		9.01
	3		8.45		8.95
SPS	1		10.25		10.39
	2		10.25		11.20
	3	^(c)	10.40		11.20
FERC Staff	1		8.97		9.47
	2		8.64		9.14
	3		8.53		9.03



(Thousands of Dollars)	April 1, 2015		Purchases		Settlements			Gains Recognized as Regulatory Assets ^(a)		June 30, 2015
Private equity investments	$	113,619	$	8,749	$	—		$	11,625	$	133,993
Real estate	67,774		4,271		(1,241		)	30		70,834
Total	$	181,393	$	13,020	$	(1,241	)	$	11,655	$	204,827

(Thousands of Dollars)	April 1, 2014		Purchases		Settlements			Gains Recognized as Regulatory Asset ^(a)		June 30, 2014
Private equity investments	$	73,801	$	2,184	$	—		$	5,138	$	81,123
Real estate	62,954		197		—			2,507		65,658
Total	$	136,755	$	2,381	$	—		$	7,645	$	146,781



(Thousands of Dollars)	Jan. 1, 2015		Purchases		Settlements			Gains Recognized as Regulatory Assets ^(a)		June 30, 2015
Private equity investments	$	101,237	$	21,131	$	—		$	11,625	$	133,993
Real estate	64,249		8,132		(2,622		)	1,075		70,834
Total	$	165,486	$	29,263	$	(2,622	)	$	12,700	$	204,827

(Thousands of Dollars)	Jan. 1, 2014		Purchases		Settlements			Gains Recognized as Regulatory Asset ^(a)		June 30, 2014
Private equity investments	$	62,696	$	10,953	$	—		$	7,474	$	81,123
Real estate	57,368		3,856		—			4,434		65,658
Total	$	120,064	$	14,809	$	—		$	11,908	$	146,781



	Three Months Ended June 30						Six Months Ended June 30
Contributions to Diluted Earnings (Loss) Per Share	2015			2014			2015			2014
GAAP earnings (loss) by segment
Regulated electric	$	0.42		$	0.37		$	0.58		$	0.74
Regulated natural gas	(0.01		)	0.03			0.15			0.18
Other ^(a)	0.01			0.02			0.01			0.04
Xcel Energy Inc. and other ^(a)	(0.03		)	(0.03		)	(0.05		)	(0.05		)
Total diluted EPS	$	0.39		$	0.39		$	0.69		$	0.91