UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended Sept. 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 October ~~26, 2015~~24, 2016
Common Stock, $2.50 par value		~~507,496,978~~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	4336
Item 3 —	Quantitative and Qualitative Disclosures about Market Risk	6157
Item 4 —	Controls and Procedures	6157

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	6158
Item 1A —	Risk Factors	6158
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	6258
Item 4 —	Mine Safety Disclosures	6258
Item 5 —	Other Information	6258
Item 6 —	Exhibits	6259

SIGNATURES		6360

	Certifications Pursuant to Section 302	1
	Certifications Pursuant to Section 906	1
	Statement Pursuant to Private Litigation	1

This Form 10-Q is filed by Xcel Energy Inc. Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado (PSCo); and Southwestern Public Service Company (SPS). Xcel Energy Inc. and its consolidated subsidiaries are also referred to herein as Xcel Energy. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries. The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin, which is operated on an integrated basis and is managed by NSP-Minnesota, is referred to collectively as the NSP System. Additional information on the wholly owned subsidiaries is available on various filings with the Securities and Exchange Commission (SEC).

Table of Contents

PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

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

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2015			2014			2015			2014			2016			2015			2016			2015
Operating revenues
Electric	$	2,667,480		$	2,616,351		$	7,105,803		$	7,215,699		$	2,799,964		$	2,667,480		$	7,209,225		$	7,105,803
Natural gas	216,019			236,649			1,216,146			1,485,464			221,956			216,019			1,046,544			1,216,146
Other	17,813			16,807			56,716			56,344			18,227			17,813			56,500			56,716
Total operating revenues	2,901,312			2,869,807			8,378,665			8,757,507			3,040,147			2,901,312			8,312,269			8,378,665

Operating expenses
Electric fuel and purchased power	1,014,726			1,079,855			2,869,563			3,188,498			1,037,263			1,014,726			2,755,083			2,869,563
Cost of natural gas sold and transported	66,071			99,344			665,109			934,073			67,566			66,071			469,754			665,109
Cost of sales — other	8,203			8,012			26,416			24,783			8,648			8,203			25,225			26,416
Operating and maintenance expenses	565,984			568,391			1,746,093			1,714,138			590,009			565,984			1,764,397			1,746,093
Conservation and demand side management program expenses	57,314			75,172			165,260			223,552			63,914			57,314			177,266			165,260
Depreciation and amortization	280,121			255,395			827,821			756,645			328,503			280,121			971,057			827,821
Taxes (other than income taxes)	123,081			117,958			389,438			358,938			117,190			123,081			400,982			389,438
Loss on Monticello life cycle management/extended power uprate project	—			—			129,463			—			—			—			—			129,463
Total operating expenses	2,115,500			2,204,127			6,819,163			7,200,627			2,213,093			2,115,500			6,563,764			6,819,163

Operating income	785,812			665,680			1,559,502			1,556,880			827,054			785,812			1,748,505			1,559,502

Other income, net	1,626			1,404			5,748			4,687			578			1,626			6,388			5,748
Equity earnings of unconsolidated subsidiaries	8,162			7,401			24,360			22,650			9,701			8,162			32,500			24,360
Allowance for funds used during construction — equity	15,427			23,337			40,728			68,852			17,199			15,427			45,042			40,728

Interest charges and financing costs
Interest charges — includes other financing costs of $6,260, $5,737, $17,819 and $17,144, respectively	152,566			143,219			441,728			421,713
Interest charges — includes other financing costs of $6,060 $6,260, $19,026 and $17,819, respectively													165,857			152,566			485,280			441,728
Allowance for funds used during construction — debt	(7,031		)	(9,948		)	(19,340		)	(29,609		)	(7,532		)	(7,031		)	(20,206		)	(19,340		)
Total interest charges and financing costs	145,535			133,271			422,388			392,104			158,325			145,535			465,074			422,388

Income before income taxes	665,492			564,551			1,207,950			1,260,965			696,207			665,492			1,367,361			1,207,950
Income taxes	239,029			195,969			432,490			435,998			238,412			239,029			471,459			432,490
Net income	$	426,463		$	368,582		$	775,460		$	824,967		$	457,795		$	426,463		$	895,902		$	775,460

Weighted average common shares outstanding:
Basic	508,031			506,082			507,585			502,983			508,941			508,031			508,840			507,585
Diluted	508,427			506,365			507,976			503,213			509,566			508,427			509,396			507,976

Earnings per average common share:
Basic	$	0.84		$	0.73		$	1.53		$	1.64		$	0.90		$	0.84		$	1.76		$	1.53
Diluted	0.84			0.73			1.53			1.64			0.90			0.84			1.76			1.53

Cash dividends declared per common share	$	0.32		$	0.30		$	0.96		$	0.90		$	0.34		$	0.32		$	1.02		$	0.96

See Notes to Consolidated Financial Statements

Table of Contents

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

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2015			2014			2015			2014			2016			2015			2016		2015
Net income	$	426,463		$	368,582		$	775,460		$	824,967		$	457,795		$	426,463		$	895,902	$	775,460

Other comprehensive income

Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $559, $567, $1,689 and $1,666, respectively	884			847			2,643			2,575
Amortization of losses included in net periodic benefit cost, net of tax of $536, $559, $1,635 and $1,689, respectively													878			884			1,954		2,643

Derivative instruments:
Net fair value decrease, net of tax of $(28), $(27), $(24) and $(22), respectively	(42		)	(42		)	(35		)	(34		)
Reclassification of losses to net income, net of tax of $446, $393, $1,210 and $1,115, respectively	706			558			1,891			1,693
Net fair value (decrease) increase, net of tax of $(2), $(28), $3 and $(24), respectively													(4		)	(42		)	4		(35		)
Reclassification of losses to net income, net of tax of $588, $446, $1,786 and $1,210, respectively													960			706			2,834		1,891
	664			516			1,856			1,659			956			664			2,838		1,856
Marketable securities:
Net fair value (decrease) increase, net of tax of $0, $1, $1 and $26, respectively	(1		)	2			1			40
Net fair value (decrease) increase, net of tax of $0, $0, $0 and $1, respectively													—			(1		)	—		1

Other comprehensive income	1,547			1,365			4,500			4,274			1,834			1,547			4,792		4,500
Comprehensive income	$	428,010		$	369,947		$	779,960		$	829,241		$	459,629		$	428,010		$	900,694	$	779,960

See Notes to Consolidated Financial Statements

Table of Contents

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

	Nine Months Ended Sept. 30						Nine Months Ended Sept. 30
	2015			2014			2016			2015
Operating activities
Net income	$	775,460		$	824,967		$	895,902		$	775,460
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	841,360			769,706			982,682			841,360
Conservation and demand side management program amortization	4,063			4,582			3,089			4,063
Nuclear fuel amortization	82,627			92,278			89,475			82,627
Deferred income taxes	429,091			433,224			479,100			429,091
Amortization of investment tax credits	(4,151		)	(4,329		)	(3,920		)	(4,151		)
Allowance for equity funds used during construction	(40,728		)	(68,852		)	(45,042		)	(40,728		)
Equity earnings of unconsolidated subsidiaries	(24,360		)	(22,650		)	(32,500		)	(24,360		)
Dividends from unconsolidated subsidiaries	29,434			27,130			34,502			29,434
Share-based compensation expense	29,765			16,536			29,872			29,765
Loss on Monticello life cycle management/extended power uprate project	129,463			—			—			129,463
Net realized and unrealized hedging and derivative transactions	18,808			(1,354		)	3,307			18,808
Other							(266		)	—
Changes in operating assets and liabilities:
Accounts receivable	85,276			(16,080		)	(29,585		)	85,276
Accrued unbilled revenues	182,425			112,406			87,015			182,425
Inventories	(47,659		)	(57,677		)	(6,203		)	(47,659		)
Other current assets	72,445			(25,901		)	80,566			72,445
Accounts payable	(116,137		)	(155,788		)	50,526			(116,137		)
Net regulatory assets and liabilities	116,068			162,134			3,911			116,068
Other current liabilities	60,293			14,683			(76,011		)	60,293
Pension and other employee benefit obligations	(82,013		)	(111,463		)	(96,350		)	(82,013		)
Change in other noncurrent assets	2,374			44,009			(11,815		)	2,374
Change in other noncurrent liabilities	(53,982		)	(33,220		)	(25,401		)	(53,982		)
Net cash provided by operating activities	2,489,922			2,004,341			2,412,854			2,489,922

Investing activities
Utility capital/construction expenditures	(2,186,369		)	(2,301,339		)	(2,186,483		)	(2,186,369		)
Proceeds from insurance recoveries	27,237			6,000			1,595			27,237
Allowance for equity funds used during construction	40,728			68,852			45,042			40,728
Purchases of investments in external decommissioning fund	(773,260		)	(499,493		)
Proceeds from the sale of investments in external decommissioning fund	753,924			494,554
Investment in WYCO Development LLC	(832		)	(2,220		)
Purchases of investment securities							(390,031		)	(773,260		)
Proceeds from the sale of investment securities							327,378			753,924
Investments in WYCO Development LLC and other							(3,962		)	(832		)
Other, net	(676		)	(1,110		)	204			(676		)
Net cash used in investing activities	(2,139,248		)	(2,234,756		)	(2,206,257		)	(2,139,248		)

Financing activities
Repayments of short-term borrowings, net	(955,500		)	(62,000		)	(480,000		)	(955,500		)
Proceeds from issuance of long-term debt	1,627,190			837,794			1,632,642			1,627,190
Repayments of long-term debt	(250,644		)	(275,708		)	(580,167		)	(250,644		)
Proceeds from issuance of common stock	5,298			178,639			—			5,298
Purchase of common stock for settlement of equity awards							(2,810		)	—
Dividends paid	(452,217		)	(417,586		)	(507,817		)	(452,217		)
Net cash (used in) provided by financing activities	(25,873		)	261,139
Net cash provided by (used in) financing activities							61,848			(25,873		)

Net change in cash and cash equivalents	324,801			30,724			268,445			324,801
Cash and cash equivalents at beginning of period	79,608			107,144			84,940			79,608
Cash and cash equivalents at end of period	$	404,409		$	137,868		$	353,385		$	404,409

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(424,878	)	$	(407,186	)	$	(461,302	)	$	(424,878	)
Cash received (paid) for income taxes, net	57,632			(4,950		)
Cash received for income taxes, net							61,245			57,632

Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable	$	284,864		$	407,706		$	221,155		$	284,864
Issuance of common stock for reinvested dividends and 401(k) plans	39,169			42,772
Issuance of common stock for reinvested dividends and equity awards							17,527			39,169

See Notes to Consolidated Financial Statements

Table of Contents

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

	Sept. 30, 2015			Dec. 31, 2014			Sept. 30, 2016			Dec. 31, 2015
Assets
Current assets
Cash and cash equivalents	$	404,409		$	79,608		$	353,385		$	84,940
Accounts receivable, net	741,230			826,506			754,248			724,606
Accrued unbilled revenues	546,067			728,492			567,852			654,867
Inventories	644,963			597,183			614,908			608,584
Regulatory assets	347,122			444,058			317,611			344,630
Derivative instruments	48,110			85,723			42,860			33,842
Deferred income taxes	352,712			246,210			195,303			140,219
Prepaid taxes	117,012			185,488			107,210			163,023
Prepayments and other	142,797			171,112			122,786			155,734
Total current assets	3,344,422			3,364,380			3,076,163			2,910,445

Property, plant and equipment, net	29,828,609			28,756,916			32,206,696			31,205,851

Other assets
Nuclear decommissioning fund and other investments	1,807,692			1,832,640			2,048,455			1,902,995
Regulatory assets	2,812,172			2,774,216			2,874,351			2,858,741
Derivative instruments	54,743			53,775			51,369			51,083
Other	182,058			175,957			67,716			32,581
Total other assets	4,856,665			4,836,588			5,041,891			4,845,400
Total assets	$	38,029,696		$	36,957,884		$	40,324,750		$	38,961,696

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	457,474		$	257,726		$	709,567		$	657,021
Short-term debt	64,000			1,019,500			366,000			846,000
Accounts payable	924,260			1,173,006			916,534			960,982
Regulatory liabilities	365,853			410,729			228,721			306,830
Taxes accrued	379,103			396,615			422,437			438,189
Accrued interest	143,124			158,536			155,005			166,829
Dividends payable	162,324			151,720			172,704			162,410
Derivative instruments	27,303			21,632			25,201			29,839
Other	561,579			475,119			457,803			490,197
Total current liabilities	3,085,020			4,064,583			3,453,972			4,058,297

Deferred credits and other liabilities
Deferred income taxes	6,390,162			5,852,988			6,851,873			6,293,661
Deferred investment tax credits	69,545			73,696			64,499			68,419
Regulatory liabilities	1,169,294			1,163,429			1,367,557			1,332,889
Asset retirement obligations	2,550,930			2,446,631			2,703,396			2,608,562
Derivative instruments	173,588			183,936			154,650			168,311
Customer advances	228,479			256,945			216,978			228,999
Pension and employee benefit obligations	863,645			936,907			843,739			941,002
Other	263,452			264,653			277,561			261,756
Total deferred credits and other liabilities	11,709,095			11,179,185			12,480,253			11,903,599

Commitments and contingencies
Capitalization
Long-term debt	12,690,751			11,499,634			13,402,583			12,398,880
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,267,264 and 505,733,267 shares outstanding at Sept. 30, 2015 and Dec. 31, 2014, respectively	1,268,168			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 Sept. 30, 2016 and Dec. 31, 2015, respectively							1,269,882			1,268,839
Additional paid in capital	5,873,440			5,837,330			5,898,896			5,889,106
Retained earnings	3,506,861			3,220,958			3,924,125			3,552,728
Accumulated other comprehensive loss	(103,639		)	(108,139		)	(104,961		)	(109,753		)
Total common stockholders’ equity	10,544,830			10,214,482			10,987,942			10,600,920
Total liabilities and equity	$	38,029,696		$	36,957,884		$	40,324,750		$	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 Sept. 30, 2015 and 2014						Retained Earnings
Balance at June 30, 2014	505,106	$	1,262,764	$	5,799,968	$	2,961,406			Accumulated Other Comprehensive Loss	$	(103,366	)		$	9,920,772
Net income						368,582								368,582
Other comprehensive income										1,365				1,365
Dividends declared on common stock						(152,601		)						(152,601		)
Issuances of common stock	318	796		9,135										9,931
Share-based compensation				6,611										6,611
Balance at Sept. 30, 2014	505,424	$	1,263,560	$	5,815,714	$	3,177,387			$	(102,001	)		$	10,154,660

Three Months Ended Sept. 30, 2016 and 2015																	Three Months Ended Sept. 30, 2016 and 2015
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
Net income						426,463								426,463											426,463						426,463
Other comprehensive income										1,547				1,547														1,547			1,547
Dividends declared on common stock						(163,247		)						(163,247		)									(163,247		)				(163,247		)
Issuances of common stock	308	770		8,665										9,435			308		770			8,665									9,435
Share-based compensation				1,566										1,566								1,566									1,566
Balance at Sept. 30, 2015	507,267	$	1,268,168	$	5,873,440	$	3,506,861			$	(103,639	)		$	10,544,830		507,267		$	1,268,168		$	5,873,440		$	3,506,861		$	(103,639	)	$	10,544,830

Balance at June 30, 2016																	507,953		$	1,269,882		$	5,896,394		$	3,643,653		$	(106,795	)	$	10,703,134
Net income																									457,795						457,795
Other comprehensive income																												1,834			1,834
Dividends declared on common stock																									(173,786		)				(173,786		)
Issuances of common stock																	48		120			—									120
Purchase of common stock for settlement of equity awards																	(48	)	(120		)	(2,021		)							(2,141		)
Share-based compensation																						4,523			(3,537		)				986
Balance at Sept. 30, 2016																	507,953		$	1,269,882		$	5,898,896		$	3,924,125		$	(104,961	)	$	10,987,942

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (Continued) (amounts in thousands)	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
Nine Months Ended Sept. 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						824,967							824,967
Other comprehensive income									4,274				4,274
Dividends declared on common stock						(455,563		)					(455,563		)
Issuances of common stock	7,452	18,631		175,960									194,591
Share-based compensation				20,441									20,441
Balance at Sept. 30, 2014	505,424	$	1,263,560	$	5,815,714	$	3,177,387		$	(102,001	)		$	10,154,660

��																Shares		Par Value			Additional Paid In Capital			Retained Earnings				Accumulated Other Comprehensive Loss				Total Common Stockholders’ Equity
Nine Months Ended Sept. 30, 2016 and 2015																Nine Months Ended Sept. 30, 2016 and 2015
Balance at Dec. 31, 2014	505,733	$	1,264,333	$	5,837,330	$	3,220,958		$	(108,139	)		$	10,214,482		505,733		$	1,264,333		$	5,837,330				$	3,220,958			$	(108,139	)		$	10,214,482
Net income						775,460							775,460											775,460								775,460
Other comprehensive income									4,500				4,500															4,500				4,500
Dividends declared on common stock						(489,557		)					(489,557		)									(489,557		)						(489,557		)
Issuances of common stock	1,534	3,835		18,874									22,709			1,534		3,835			18,874											22,709
Share-based compensation				17,236									17,236								17,236											17,236
Balance at Sept. 30, 2015	507,267	$	1,268,168	$	5,873,440	$	3,506,861		$	(103,639	)		$	10,544,830		507,267		$	1,268,168		$	5,873,440		$	3,506,861			$	(103,639	)		$	10,544,830

Balance at Dec. 31, 2015																507,536		$	1,268,839		$	5,889,106		$	3,552,728			$	(109,753	)		$	10,600,920
Net income																								895,902								895,902
Other comprehensive income																												4,792				4,792
Dividends declared on common stock																								(520,968		)						(520,968		)
Issuances of common stock																486		1,216			15,110											16,326
Purchase of common stock for settlement of equity awards																(69	)	(173		)	(2,810		)									(2,983		)
Share-based compensation																					(2,510		)	(3,537		)						(6,047		)
Balance at Sept. 30, 2016																507,953		$	1,269,882		$	5,898,896		$	3,924,125			$	(104,961	)		$	10,987,942

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of Xcel Energy Inc. and its subsidiaries as of Sept. 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 nine months ended Sept. 30, ~~2015~~2016 and ~~2014;~~2015; and its cash flows for the nine months ended Sept. 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 Sept. 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 ~~does not expect~~implemented the guidance on Jan. 1, 2016, and other than the classification of certain real estate investments held within the Nuclear Decommissioning Trust as non-consolidated variable interest entities, the implementation ~~of ASU 2015-02 to~~did not have a ~~material~~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 (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.

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3.	Selected Balance Sheet Data


(Thousands of Dollars)	Sept. 30, 2015			Dec. 31, 2014			Sept. 30, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	793,188		$	884,225		$	802,827		$	776,494
Less allowance for bad debts	(51,958		)	(57,719		)	(48,579		)	(51,888		)
	$	741,230		$	826,506		$	754,248		$	724,606


(Thousands of Dollars)	Sept. 30, 2015		Dec. 31, 2014		Sept. 30, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	291,301	$	244,099	$	306,544	$	290,690
Fuel	212,728		183,249		181,265		202,271
Natural gas	140,934		169,835		127,099		115,623
	$	644,963	$	597,183	$	614,908	$	608,584

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(Thousands of Dollars)	Sept. 30, 2015			Dec. 31, 2014			Sept. 30, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	35,022,960		$	33,203,139		$	37,335,785		$	36,464,050
Natural gas plant	4,818,049			4,643,452			5,149,959			4,944,757
Common and other property	1,615,290			1,611,486			1,741,615			1,709,508
Plant to be retired ^(a)	42,336			71,534			36,852			38,249
Construction work in progress	1,679,178			2,005,531			1,844,525			1,256,949
Total property, plant and equipment	43,177,813			41,535,142			46,108,736			44,413,513
Less accumulated depreciation	(13,724,333		)	(13,168,418		)	(14,218,683		)	(13,591,259		)
Nuclear fuel	2,414,986			2,347,422			2,469,772			2,447,251
Less accumulated amortization	(2,039,857		)	(1,957,230		)	(2,153,129		)	(2,063,654		)
	$	29,828,609		$	28,756,916		$	32,206,696		$	31,205,851


^(a)	~~PSCo’s Cherokee Unit 3 was retired in August 2015.~~ In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural ~~gas, as approved by the Colorado Public Utilities Commission (CPUC).~~gas. PSCo also expects Craig Unit 1 to be early retired in approximately 2025. 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 2012-2015, 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. 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 Sept. 30, ~~2015,~~2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in ~~$13~~$14 million of income tax expense for the 2009 through 2011 claims, the ~~recently filed~~ 2013 ~~claim,~~and 2014 claims and the anticipated claim for ~~2014. As~~2015. In the fourth quarter of ~~Sept. 30,~~ 2015, the IRS ~~had begun~~forwarded the ~~appeals process;~~issue to the Office of Appeals (Appeals). In 2016 the IRS audit team and Xcel Energy presented their cases to Appeals; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s ~~2009-2011~~2009 through 2011 federal income tax returns, following extensions, expires in ~~December 2016 following an extension to allow additional time for~~June 2017. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of the ~~appeals process.~~IRS’s proposed adjustment of the carryback claims. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Sept. 30, ~~2015,~~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 Sept. 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		~~2011~~2012

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

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

In August 2016, Wisconsin began an audit of years 2012 and 2013. As of Sept. 30, 2016, Wisconsin had not proposed any adjustments. As of Sept. 30, 2016, there were no other state income tax audits in progress.

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~~As of Sept. 30, 2015, there were no state income tax audits in progress.~~

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

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


(Millions of Dollars)	Sept. 30, 2015		Dec. 31, 2014		Sept. 30, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	15.8	$	16.2	$	27.7	$	25.8
Unrecognized tax benefit — Temporary tax positions	60.6		50.3		103.1		94.9
Total unrecognized tax benefit	$	76.4	$	66.5	$	130.8	$	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)	Sept. 30, 2015			Dec. 31, 2014			Sept. 30, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(39.2	)	$	(28.5	)	$	(42.1	)	$	(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~~Appeals and audit progress, the Minnesota, Texas and Wisconsin audits progress, and other state audits resume. As the IRS ~~appeals process moves closer to completion,~~Appeals and IRS, Minnesota, Texas and Wisconsin audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately ~~$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 Sept. 30, ~~2015~~2016 and Dec. 31, ~~2014~~2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 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 ~~the consolidated financial statements included in~~ Xcel Energy Inc.’s Quarterly Reports on

Form 10-Q for the quarterly periods ended March 31, ~~2015~~2016 and June 30, ~~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. 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.~~2016.

Settlement Agreement

In ~~May 2015,~~August 2016, NSP-Minnesota reached a settlement with the ~~MPUC ordered a 2014 rate increase~~Minnesota Department of Commerce (DOC), Xcel Large Industrials, the Minnesota Chamber of Commerce, the Commercial Group, the Suburban Rate Authority, the City of Minneapolis, the Industrial, Commercial, and ~~a 2015 step increase.~~Institutional Group, and the Energy CENTS Coalition, which resolves all revenue requirement issues in dispute. The ~~total increase was estimated to be $166.1 million, or 5.9 percent, consisting~~settlement agreement requires the approval of $58.9 million and $125.2 million in 2014 and 2015, respectively, and an $18.0 million adjustment related to disallowance of certain Monticello Life Cycle Management (LCM)/Extended Power Uprate (EPU) costs. 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.MPUC.

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~~In July 2015,~~Key terms of the ~~MPUC deliberated~~settlement are listed below:

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

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

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

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

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

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

An ROE of ~~its order~~9.2 percent and ~~determined~~an equity ratio of 52.5 percent;

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

Continued use of all existing riders during the ~~Monticello EPU project was not yet used-and-useful, as final approval related~~four-year term, however no new riders or legislative additions would be utilized during the four-year term;

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

A four-year stay out provision for rate cases.

Compliance steps recommended by the ~~full EPU uprate condition had not been received from~~settling parties to implement the Nuclear Regulatory Commission (NRC) as of June 30, 2015. As a result, $13.8 million was excluded from final rates. Monticello subsequently received final NRC compliance approval in July 2015. The MPUC also approved 2015 interim rates effective March 3, 2015settlement:

A property tax true-up mechanism for 2017-2019; and ~~stated that the 2014 interim rate refund obligation be netted against the 2015 interim rate revenue under-collections.~~

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



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


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


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

The ~~MPUC’s decisions resulted in a total estimated 2014 and 2015 annual~~revised schedule for the Minnesota rate ~~increase of $149.4 million, or 5.3 percent.~~case is listed below:

~~The following table outlines~~Administrative law judge (ALJ) report — March 3, 2017; and

MPUC decision — June 2017.

A current liability that is consistent with the ~~impact~~settlement and represents NSP-Minnesota’s best estimate of ~~the MPUC’s July decision:~~

(Millions of Dollars) MPUC July Decision
2014 and 2015 step 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 2014 and 2015 step increase $ 149.4
Impact of interim rate effective March 3, 2015 (3.6 )
Estimated revenue impact $ 145.8
a refund obligation for 2016 associated with interim rates was recorded as of Sept. 30, 2016.

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

Annual Automatic Adjustment (AAA) of 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. 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 AAA fiscal year ended June 30, 2015. NSP-Minnesota expects a MPUC decision in mid-2017.

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

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

In March 2015, the MPUC voted to allow for full recovery, including a return, on ~~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.~~flows.

~~NSP-Minnesota – 2016 Transmission Cost Recovery (TCR) Rate Filing~~ — In October 2015, NSP-Minnesota submitted its 2016 TCR filing with the MPUC, requesting recovery of $19.2 million of 2016 transmission investment costs not included in electric base rates. The 2016 TCR rider filing includes an option to keep within the TCR rider approximately $59.1 million of revenue requirements associated with two CapX2020 projects completed in 2015 or to include these revenue requirements in electric base rates during the interim rate implementation of the next electric rate case. If the MPUC opts to maintain the projects in the rider, the TCR rider revenue requirements would increase to $78.3 million.

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

~~NSP-Minnesota – South Dakota Infrastructure Rider~~ — In October 2015, NSP-Minnesota filed its 2016 infrastructure rider filing with the SDPUC, requesting approval for recovery of $10.3 million in 2016 revenue requirements for rates effective Jan. 1, 2016. As part of the South Dakota 2015 electric rate case, the infrastructure rider was refreshed with new projects and was also expanded as a mechanism to allow for possible recovery of other investments related to generation, transmission, and distribution. A SDPUC decision is expected in the fourth quarter of 2015.

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NSP-Wisconsin

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

Wisconsin ~~2016~~2017 Electric and Gas Rate Case — In ~~May 2015,~~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.

The electric rate ~~filing~~request is ~~based on a 2016 forecast test year, a ROE~~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 for the natural gas utility.~~adjacent area in Ashland, Wis.

~~On Oct. 1, 2015,~~No changes are being requested to the capital structure or the 10.0 percent ROE authorized by the PSCW in the 2016 rate case. As part of an agreement with stakeholders to limit the size and scope of the case, NSP-Wisconsin also agreed to an earnings cap, solely for 2017, in which 100 percent of the earnings in excess of the authorized ROE would be refunded to customers.

In August 2016, the PSCW Staff (Staff) and ~~other~~the intervenors ~~including the Citizens Utility Board,~~ filed their direct testimony in the case. The ~~PSCW~~ Staff recommended an electric rate increase of ~~$10.4~~$19.5 million, or ~~1.5~~2.7 percent and a natural gas rate increase of ~~$3.0~~$4.8 million, or ~~2.5 percent, based on a ROE~~3.9 percent. The Staff adjustments reflect revisions to previously forecasted rate base as well as fuel and purchased power expense. The Staff’s recommended rate increase also encompasses the PSCW’s July 2016 decision to remove the $9.5 million fuel refund credit from the rate case and refund that amount directly to customers in 2016. Adjusting for the treatment of ~~10.0~~the fuel refund, the Staff’s recommendation is $7.4 million less than NSP-Wisconsin’s request.

On Oct. 26, 2016, the PSCW verbally approved an electric rate increase of approximately $22.5 million, or 3.2 percent, and ~~an equity ratio~~a natural gas rate increase of ~~52.5~~$4.8 million, or 3.9 percent. The ~~Citizens Utility Board recommended a ROE of 8.75 percent. None of~~difference between the ~~intervenors presented a complete revenue requirements analysis.~~Staff’s recommendation and the PSCW’s approved electric increase is attributable to an increase in forecasted fuel and purchased power expense. Consistent with long-standing PSCW policy, these costs were updated prior to the PSCW’s decision to reflect current market forecasts. The ~~majority of the~~ PSCW ~~Staff adjustments relate to ROE, compensation issues and capital related forecast disputes.~~

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

~~Initial Brief — Nov. 12, 2015;~~

~~Reply Brief — Nov. 19, 2015;~~

~~A PSCW decision is anticipated in December 2015; and~~

~~New rates effective on or about Jan. 1, 2016.~~

~~PSCo~~

~~Pending Regulatory Proceedings — CPUC~~

~~PSCo – Colorado 2015 Multi-Year Gas Rate Case~~ ~~— In March 2015, PSCo filed a multi-year request~~approved NSP-Wisconsin’s requested natural gas rate increase consistent 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.Staff’s recommendation.

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~~major components of the ~~subsequent periods in~~retail electric rate increase, the ~~multi-year plan (MYP)~~Staff’s recommendation, and an equity ratio of 56 percent. The rate case requests a 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:PSCW’s approval are summarized below:

(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



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

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^(a)

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

^(b)

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

~~In June 2015, the CPUC Staff (Staff) and the Office of Consumer Counsel (OCC) issued their 2015 base rate recommendations. The following table reflects the current positions of Staff and OCC:~~

(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 HTY (10.5 ) (16.4 )
Operating and maintenance (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

In July 2015, PSCo filed rebuttal testimony, maintaining its request for a multi-year plan and requested ROEs and reflecting the most recent sales forecast. 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.~~

Interim rates, subject to refund, were also implemented, effective Oct. 1, 2015, based on PSCo’s direct testimony. PSCo is expecting the ALJ’s Recommended Decision in November 2015. The final CPUC decision is expected no later than January 2016.

~~PSCo~~ — ~~Annual Electric Earnings Test~~ — 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. As of Sept. 30, 2015, PSCo has recognized management’s best estimate of the expected customer refund obligation for the 2015 earnings test, based on annual forecasted information.

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~~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~~NSP-Wisconsin anticipates 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-up 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 percent of net economic benefits up to a maximum annual incentive of $30 million. For the years 2015 through 2020, the annual electric energy savings goal is 400 GWh perfinal written order later this year, with ~~an annual earnings limit of $84.3 million.~~

~~In July 2015, the CPUC approved PSCo’s 2015-2016 DSM plan:~~

~~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.~~new rates effective on Jan. 1, 2017.

SPS

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

~~SPS –~~Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of $64.8 million, which it subsequently revised to $42.1 million. In 2015, the PUCT approved an overall rate decrease of approximately $4.0 million, net of rate case expenses. In April 2016, SPS filed an appeal, with the Texas State District Court, of the PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital structure, incentive compensation and wholesale load reductions. The hearing in the appeal is scheduled for February 2017.

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,~~SPS’ required update filing in April 2016, SPS revised its requested rate increase to ~~$58.9 million based on updated information.~~$68.6 million.

~~SPS is seeking a waiver of~~Pursuant to legislation passed in Texas in 2015, the ~~PUCT post-test year adjustment rule which would allow for inclusion of $392 million (SPS total company) additional capital investment for~~final rates established in the ~~period~~case will be effective retroactive to July ~~1, 2014 through Dec. 31, 2014.~~

~~In June 2015, SPS filed rebuttal testimony supporting a revised rate increase of approximately $42.1 million, or 4.4 percent.~~20, 2016.

~~On Oct. 12, 2015,~~In August 2016, several intervenors filed direct testimony in response to SPS’ rate request, including: PUCT Staff (Staff), the administrative law judges (ALJs) issued their Proposal for Decision (PFD) and recommended a rate increase of approximately $1.2 million, based on a ROE of 9.70 percent and an equity ratio of 53.97 percent.

~~The following table reflects the positions of~~ Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), Texas Industrial Energy Consumers (TIEC), and the ~~PUCT Staff (Staff), SPS as well as the estimated recommendation~~State of ~~the ALJs:~~

SPS Rebuttal Testimony
ALJs’ PFD ^(a)
(Millions of Dollars) AXM OPUC Staff
SPS’ revised rate request $ 58.9
$ 58.9
$ 58.9
$ 58.9
$ 42.1
Investment for capital expenditures — post-test year adjustments (11.3 ) (23.8 ) (23.8 ) —
(16.7 )
Lower ROE (10.9 ) (13.5 ) (12.1 ) —
(6.3 )
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 ) (5.3 )
Depreciation expense (13.3 ) —
—
—
(3.9 )
Property taxes —
(1.2 ) (4.4 ) (1.8 ) (3.7 )
Revenue adjustments (2.2 ) (0.2 ) —
—
—
Wholesale load reductions (13.2 ) —
(11.1 ) —
—
Southwest Power Pool (SPP) transmission expansion plan —
—
—
(7.3 ) (4.2 )
Other, net (1.7 ) (0.6 ) (2.2 ) (1.8 ) (0.6 )
Total recommendation $ (13.6 ) $ 1.8
$ (2.6 ) $ 46.4
$ 1.4
Adjustment to move rate case expenses to a separate docket —
—
—
(4.3 ) (0.2 )
Recommendation, excluding rate case expenses $ (13.6 ) $ 1.8
$ (2.6 ) $ 42.1
$ 1.2
Texas’ agencies.

^(a)The ~~ALJs’ recommendation reflects proposed adjustments to SPS’ rebuttal testimony, as of Oct. 12, 2015, which supports~~Staff recommended a ~~$42.1 million rate increase.~~

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SPS subsequently filed a letter notifying the PUCT it had concerns regarding the calculation. On Oct. 28, 2015, the Staff issued a revised calculation reflecting corrections to the PFD. The ALJs’ revised recommended rate increase ~~is $14.4 million.~~of approximately $32.9 million, based on a ROE of 9.30 percent and an equity ratio of 51 percent. The Staff’s proposed rate increase reflects imputed revenues for power factor adjustment charges and weather normalization;

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

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

~~New rates will be made effective retroactive~~In October 2016, SPS and various parties reached an agreement in principle in the Texas rate case. SPS and the parties are documenting the settlement, and expect to ~~June 11, 2015 as established~~file with the PUCT in the fourth quarter of 2016. Any settlement would require approval of the PUCT, with a decision expected by the ~~PUCT. A PUCT decision is expected in December 2015.~~end of 2016 or early 2017.

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

~~SPS –~~ New Mexico 2015 Electric Rate Case —In October 2015, SPS filed an electric rate case with the NMPRC ~~for a net increase in base rates of approximately $24.3 million for the New Mexico retail jurisdiction. The proposed net amount reflects~~seeking an increase in non-fuel base rates of $45.4 million. The proposed increase would be offset by a decrease in base fuel revenue of approximately $21.1 million. The rate filing was based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.25 percent, an electric rate base of approximately $734 million and an equity ratio of 53.97 percent.

In August 2016, the NMPRC approved a black-box stipulation that resulted in a non-fuel base rate increase of $23.5 million and a decrease in base fuel revenue of approximately $21.1 million. The decrease in base fuel revenue will be reflected in adjustments ~~collected through~~to the fuel and purchased power cost adjustment clause. The rate filing is based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.25 percent, an electric jurisdictional rate base of approximately$734 million and an equity ratio of 53.97 percent.

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

(Millions of Dollars) Request
2015 base period deficiency $ 19.7
Capital expenditures — post-test year adjustments
12.3
Depreciation, higher rates reflecting changes in depreciable lives, interim retirements and net salvage 3.7
Transmission revenue and expense, including charges paid to SPP for construction of regionally shared transmission projects 2.0
ROE, reflecting an increase from 9.96 percent to 10.25 percent 1.6
Rider revenue adjustments - gross receipts tax 1.3
Other, net 4.8
Requested rate increase $ 45.4

~~A NMPRC decision and implementation of final rates is anticipated in the second half of 2016. In June 2015, the NMPRC dismissed a~~SPS plans to file another base rate case ~~filing using~~in November 2016 utilizing a future test year ~~based on new precedent. SPS has appealed that decision to the New Mexico Supreme Court.~~ending June 2018.

Pending ~~and Recently Concluded~~ Regulatory Proceedings — ~~Federal Energy Regulatory Commission (FERC)~~FERC

Midcontinent Independent System Operator, Inc. (MISO) ROE Complaints/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against ~~certain~~ 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 for being an independent transmission company), effective Nov. 12, 2013.

Subsequently, the FERC issued and upheld 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.

The ROE complaint was set for full hearing procedures. The complainants and intervenors filed testimony recommending a ROE between 8.67 percent and 9.54 percent. The FERC staff recommended a ROE of 8.68 percent. The MISO TOs recommended a ROE not less than 10.8 percent. An ALJ initial decision is anticipated to be issued by November 2015 and a FERC order is expected to be issued no earlier than 2016.

Certain MISO TOs requested FERC approval of a 50 basis point RTO membership ROE adder, which was approved effective Jan. 6, 2015, subject to the outcome of the ROE complaint. The total ROE, including the RTO membership adder, may not exceed the top of the discounted cash flow range under the new ROE methodology. Certain intervenors sought rehearing of the FERC order granting the ROE adder; FERC action is pending.

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~~Certain intervenors filed~~In December 2015, an ALJ initial decision recommended the FERC approve a ROE of 10.32 percent, which the FERC upheld in an order issued on Sept. 28, 2016. This ROE is applicable for the 15 month refund period from Nov. 12, 2013 to Feb. 11, 2015, and prospectively from the date of the FERC order. The total prospective ROE is 10.82 percent, which includes a previously approved 50 basis point adder for RTO membership.

In February 2015, a second complaint ~~in February 2015~~seeking to reduce the MISO region ROE from 12.38 percent to 8.67 percent prior to ~~an adder. A hearing has been~~any adder was filed, which the FERC set ~~and~~for hearings, resulting in a second period of potential refund ~~effective date of~~from Feb. 12, 2015 ~~was established.~~to May 11, 2016. The ~~complainants~~MPUC, the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission and ~~intervenors filed direct testimony in September 2015~~the DOC joined a joint complainant/intervenor initial brief recommending ~~ROEs between 8.72 percent and 9.13~~an ROE of approximately 8.81 percent. FERC staff recommended a ROE of 8.78 percent. The MISO TOs ~~filed answering testimony on Oct. 20, 2015, recommending~~recommended a ROE of ~~not less than 10.75~~10.92 percent. ~~FERC staff is expected to file testimony in November 2015, and~~On June 30, 2016, the ALJ recommended a ~~hearing is scheduled for February 2016. An ALJ initial~~ROE of 9.7 percent, the midpoint of the upper half of the discounted cash flow range. A FERC decision is expected in ~~June~~2017.

As of Sept. 30, 2016, ~~with~~NSP-Minnesota has recognized a ~~FERC decision~~current liability for the Nov. 12, 2013 to Feb. 11, 2015 complaint period based on the 10.32 percent ROE provided in ~~late 2016 or in 2017. Currently, the ROE refund obligation initiated under the November 2013 complaint is effective through May 2016. The MISO TOs sought rehearing of~~ the FERC ~~decision to allow back-to-back complaints. NSP-Minnesota and NSP-Wisconsin sought rehearing of the FERC’s decision not to~~ order, changes to the ROE used by non-jurisdictional MISO transmission owners (more than 20 municipal, cooperative and other utilities who are not respondents to the ROE complaints), which equals the ROE presently used by the jurisdictional MISO TOs. FERC action is pending.

~~NSP-Minnesota recorded~~as well as a current liability representing the ~~current~~ best estimate of ~~a refund obligation associated with~~ the ~~new~~final ROE ~~as of Sept. 30, 2015. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $7 million and $9 million annually~~ for the ~~NSP System.~~second complaint period.

~~SPS – Global Settlement Agreement~~Southwest Power Pool, Inc. (SPP) Open Access Transmission Tariff (OATT) Upgrade Costs — ~~In August 2015, SPS, Golden Spread Electric Cooperative, Inc. (Golden Spread), four New Mexico Cooperatives, West Texas Municipal Power Agency (WTMPA), Public Service Company~~Under the SPP OATT, costs of ~~New Mexico (PNM) and Tri-County Electric Cooperative, Inc. (Tri-County) filed a settlement agreement with~~participant-funded, or “sponsored,” transmission upgrades may be recovered, in part, from other SPP customers whose transmission service depends on capacity enabled by the ~~FERC that would provide a comprehensive resolution of nine pending matters in dispute between SPS and~~upgrade. The SPP OATT has allowed SPP to collect charges since 2008, but to date SPP has not charged its customers any amounts attributable to these ~~wholesale production and transmission customers, including the~~upgrades. ~~2004 FERC Complaint Case, the~~ ~~Wholesale Rate Complaints, the~~ ~~2015 Formula Rate Change Filing~~ ~~and the~~ ~~Sale of Texas Transmission Assets~~ ~~as discussed below. Key terms of the settlement agreement include:~~

A settlement payment to Golden Spread for $44.9 million and withdrawal of the SPS and the New Mexico Cooperatives’ requests for rehearing of the August 2013 FERC order ruling that SPS is a 3 coincident peak (CP) system;

A settlement payment to PNM of $4.2 million and the withdrawal of the PNM request for rehearing of the August 2013 FERC order denying PNM’s challenge to the 2008 FERC ruling regarding SPS’ fuel cost adjustment practices;

Withdrawal of the Golden Spread Wholesale Rate Complaints, resulting in no change to the then-effective production and transmission ROEs for the period April 20, 2012 through Oct. 19, 2014, and withdrawal of the SPS appeal of the FERC orders in those proceedings to the United States District Court of Appeals for the District of Columbia Circuit (D.C. Circuit);

A reduction in the SPS transmission ROE to 10.5 percent (including the 50 basis point SPP regional transmission organization membership adder) and the production ROE in the Golden Spread and New Mexico Cooperatives production formula rates to 10.0 percent effective Oct. 20, 2014, and establishment of a limited moratorium that precludes any increase or decrease in these effective ROEs through 2019;

Utilization of the 12 CP production cost allocation methodology in the Golden Spread, New Mexico Cooperatives and WTMPA production formula rates and a moratorium precluding all settlement parties from seeking to change from the 12 CP methodology during the remaining term of the Golden Spread production contract (currently scheduled to expire in May 2019);

SPS agrees to reduce its production formula rates retroactive to Jan. 1, 2015 to reflect full year implementation of reduced depreciation and certain other costs; the FERC had allowed these reductions to be effective July 1, 2015;

SPS agrees to make certain revisions to its transmission formula rate, effective Jan. 1, 2016, to provide for a sharing of the wholesale portion of any gain on a future sale of transmission assets; other parties agree not to challenge the non-sharing of the gain SPS recorded on prior and current transmission asset transactions with Sharyland Distribution and Transmission Services, LLC (Sharyland) and Oncor Electric Delivery Company LLC;

~~SPS agrees not to file with FERC to increase transmission depreciation rate rates effective prior to Jan. 1, 2017; and~~

SPS agrees not to transfer Tri-County from its current stated rate production service agreement to a production formula rate effective prior to Jan. 1, 2017. Tri-County agrees that it will not contest implementation of the formula rate as of that date.

On Oct. 29, 2015, the FERC issued an order approving the settlement agreement. The terms are effective 30 days after issuance. As a result of the settlement, SPS expects to recognize a net gain of approximately $7.9 million in the fourth quarter of 2015. The settlement also resolves the following:

~~2004 FERC Complaint Case Orders~~— In August 2013, the FERC issued an order related to a 2004 complaint case brought by Golden Spread, a wholesale cooperative customer, and PNM, a former wholesale customer, and also issued an Order on Initial Decision in a subsequent 2006 production rate case filed by SPS.

The original complaints included two key components: 1) a base rate complaint, including the appropriate demand-related CP cost allocator; and 2) a claim regarding alleged inappropriate fuel cost adjustment practices. The FERC had determined in April 2008 that the demand-related cost allocator and fuel cost adjustment practices utilized by SPS were appropriate.

~~Table of Contents~~

In the August 2013 Orders, the FERC 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 CP rather than a 12 CP system. The FERC also clarified its previous ruling on fuel cost adjustment practices and reaffirmed that the refunds in question should only apply to firm requirements customers.

In ~~September 2013,~~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 ~~the New Mexico Cooperatives~~ and ~~PNM each filed requests for~~certain other parties requested rehearing of the FERC ~~ruling on the CP allocation and/or refund decision. As of Dec. 31, 2014, SPS had accrued $50.4 million related~~order. In September 2016, SPP provided further information regarding additional costs, primarily due to the ~~August 2013 Orders~~system-wide claw back of point to point revenues previously distributed to SPS and other entities. Amounts due to SPP are expected to be paid over a five-year period commencing November 2016 under an ~~additional $1.9~~optional payment plan that was approved by the FERC in September 2016 and elected by SPS in October 2016. Based on SPP’s most recent calculation in October 2016, estimated costs would be approximately $12 million ~~of principal~~to $14 million, and ~~interest has been accrued during 2015.~~SPS anticipates these costs would be recoverable through regulatory mechanisms.

~~Wholesale Rate Complaints~~ — In April 2012, Golden Spread filed a rate complaint alleging that the base ROE included in the SPS production formula rate for Golden Spread of 10.25 percent, and the SPS transmission formula rate ROE of 11.27 percent are unjust and unreasonable, and requested that the base ROEs be reduced 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 base ROE in the SPS production formula rate for Golden Spread and transmission formula rates be reduced to 9.15 percent and 9.65 percent, respectively, effective July 19, 2013. In June 2014, the FERC issued orders consolidating these ROE complaints, setting the complaints for hearing procedures and granting the complainant’s requested refund effective dates. SPS subsequently sought rehearing. In May 2015, FERC denied rehearing. In July 2015, SPS appealed the FERC orders to the D.C. Circuit.

A third ROE rate complaint was filed in October 2014 by Golden Spread, along with the New Mexico Cooperatives and WTMPA, requesting that the ROE in the SPS production formula rates for Golden Spread and the New Mexico Cooperatives and SPS transmission formula rate, be reduced 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. SPS subsequently sought rehearing. FERC has not acted on the SPS rehearing request.

~~2015 Formula Rate Change Filing~~ — In January 2015, SPS filed to revise the production formula rates for Golden Spread, the four New Mexico Cooperatives and WTMPA, effective Feb. 1, 2015. The filing proposed several modifications, including a reduction in wholesale depreciation rates and the use of a 12 CP demand-related cost allocator for all wholesale customers. On March 31, 2015, the FERC accepted this filing, effective July 1, 2015, subject to refund and settlement judge or hearing procedures.

~~Sale of Texas Transmission Assets~~ — In March 2013, SPS reached an agreement to sell certain segments of SPS’ transmission lines and two related substations to Sharyland. In 2013, SPS received all necessary regulatory approvals for the transaction. In December 2013, SPS received $37.1 million and recognized a pre-tax gain of $13.6 million and regulatory liabilities for retail jurisdictional gain sharing of $7.2 million. The gain is reflected in the consolidated statement of income as a reduction to O&M expenses. In December 2014, Golden Spread submitted a preliminary challenge under the SPS transmission formula rate procedures asserting the gain should be shared with wholesale transmission customers. SPS disputed this claim. In October 2015, the FERC denied rehearing on the matter.


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 Reports on Form 10-Q for the quarterly periods ended March 31, ~~2015~~2016 and June 30, ~~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 3,537 MW and 3,698 MW of capacity under long-term PPAs as of Sept. 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.~~2041.

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Guarantees and Bond Indemnifications

Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities under specified agreements or transactions. The guarantees and bond indemnities issued by Xcel Energy Inc. guarantee payment or performance by its subsidiaries. As a result, Xcel Energy Inc.’s exposure under the guarantees and bond indemnities is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries ~~limit the exposure to~~have a stated maximum ~~amount stated in the guarantees and bond indemnities.~~guarantee or indemnity amount. As of Sept. 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)	Sept. 30, 2015		Dec. 31, 2014		Sept. 30, 2016		Dec. 31, 2015
Guarantees issued and outstanding	$	12.9	$	13.9	$	19.0	$	12.5
Current exposure under these guarantees	0.1		0.2		0.1		0.1
Bonds with indemnity protection	42.5		31.4		43.0		41.3

Other Indemnification Agreements

Xcel Energy Inc. and its subsidiaries provide indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. The maximum ~~potential amount of~~ future payments under these indemnifications cannot be reasonably estimated as the ~~obligated~~dollar amounts ~~of these indemnifications~~are 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~~property, 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 where NSP-Wisconsin believes wood treating operations were conducted;~~; and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments).

~~The U.S.~~In 2012, under a settlement agreement with the United States Environmental Protection Agency (EPA) issued its Record of Decision (ROD) in 2010, which describes the preferred remedy the EPA has selected for the cleanup of the Ashland site. For the Sediments at the Ashland site, the ROD preferred remedy is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). The ROD also identifies the possibility of a wet conventional dredging only remedy for the Sediments (the Wet Dredge), ~~contingent upon the completion of a successful Wet Dredge pilot study.~~

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.

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In October 2012, 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, NSP-Wisconsin agreed to ~~perform the remediation of~~remediate 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 excavation and treatment, as well as containment wall remedies were completed in early 2015. In fall 2015, the ground water remedy was initiated at the site with the installation of groundwater wells and the start of construction on the groundwater treatment plant. The final design for the Phase I remedy was approved by the EPA in September 2015.Site). The current cost estimate for the cleanup of the Phase I Project Area is approximately ~~$57~~$71.4 million, of which approximately ~~$39~~$52.6 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~~NSP-Wisconsin performed a wet dredge pilot study in the summer of 2016 and demonstrated that a wet dredge remedy can meet the performance standards for remediation of the Sediments. As a result, the EPA authorized NSP-Wisconsin to extend the wet dredge pilot to additional areas of the Site. Settlement negotiations are ongoing between the EPA and NSP-Wisconsin regarding ~~who will pay for or perform~~ the performance of the full scale cleanup of the ~~Sediments and what remedy will~~Sediments. If a court-approved settlement can 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. 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 to 30 percent lower. In November 2013, NSP-Wisconsin submitted a revised Wet Dredge pilot study work plan proposal to the EPA. In May 2014, NSP-Wisconsin entered into a final administrative order on consent (AOC) for the Wet Dredge pilot study with the EPA. In early 2015, NSP-Wisconsin entered into an AOC to construct a breakwater at the site to serve as wave attenuation and containment for a wet dredge pilot study and full scale sediment remedy at the site. Construction of the breakwater is underway with anticipated completion in early 2016. A wet dredge pilot study is anticipated to commence in summer 2016.

~~In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site. A final settlement has been~~ reached ~~between NSP-Wisconsin, along~~ with the EPA, ~~and two~~NSP-Wisconsin anticipates a full scale wet dredge remedy of the ~~PRPs, Wisconsin Central Ltd.~~Sediments could be performed beginning as early as 2017, 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 entered into 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 approvedpotentially conclude 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. Trial with the remaining PRPs for this matter, County of Ashland and City of Ashland, took place in May 2015. In September 2015, the Court ruled that the County of Ashland is not a liable party and the City of Ashland, although a liable party, is not required to contribute any funds to the cleanup of the site. NSP-Wisconsin filed a notice of appeal with the Seventh Circuit Court of Appeals in October 2015.2018.

At Sept. 30, ~~2015~~2016 and Dec. 31, ~~2014,~~2015, NSP-Wisconsin had recorded a total liability of ~~$95.7~~$84.6 million and ~~$107.6~~$94.4 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $16.6 million and $28.9 million, respectively, was considered a current liability.entire site. 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 and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.cost.

NSP-Wisconsin has deferred the unrecovered portion of the estimated ~~site~~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 the PSCW to be prudent, utilities are allowed to recover those deferred 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.

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~~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.~~Site. In ~~December~~ 2012, the PSCW ~~recognized the potential magnitude of the future liability for the cleanup at the Ashland site and granted an exception~~agreed to ~~its existing policy at the request of NSP-Wisconsin. The elements of this exception include: (1) approval~~allow NSP-Wisconsin to ~~begin recovery of estimated Phase 1 Project~~pre-collect certain 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 recovery of 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 through 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 ~~December 2015.~~2017.

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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 ~~which may~~were discovered in a right-of-way in Fargo, N.D. that appeared to be ~~related to~~associated with 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,~~companies. NSP-Minnesota removed ~~the~~ impacted soils and other materials from the ~~project area. NSP-Minnesota is undertaking further~~right-of-way at that time and commenced an investigation ~~of the location~~ of the historic MGP ~~site~~ and ~~nearby properties. At this time, NSP-Minnesota’s~~adjacent properties (the Fargo MGP Site). Based on the investigation that concluded in the third quarter of 2016, NSP-Minnesota has recommended that targeted source removal of impacted soils and historic MGP infrastructure should be performed, subject to further input from the North Dakota Department of Health, the City of Fargo, N.D., current property owners and other stakeholders.

NSP-Minnesota has initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota agreed to the parties’ request for a stay of the litigation until November 2016 to allow NSP-Minnesota time to investigate site ~~is considered preliminary as information is still being gathered.~~conditions. NSP-Minnesota intends to seek an additional stay of the litigation.

As of Sept. 30, 2016 and Dec. 31, 2015, NSP-Minnesota had recorded a liability of ~~$1.4~~$12.2 million and $2.7 million, respectively, for the Fargo MGP Site, with the increase due to the remediation activities proposed by NSP-Minnesota. In December 2015, the NDPSC approved NSP-Minnesota’s request to defer costs associated with the Fargo MGP Site, resulting in deferral of all investigation and response costs with the exception of 12 percent allocable to the Minnesota jurisdiction. Uncertainties related to ~~further investigation~~the liability recognized include obtaining access and ~~additional planned activities. Uncertainties include~~approvals from stakeholders to perform the ~~nature and cost of the additional~~proposed 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 2015, NSP-Minnesota filed a 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.

Environmental Requirements

Water and Waste

~~Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG)~~Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In ~~September~~April 2015, the EPA ~~issued~~published a final ~~ELG~~ rule ~~for power plants that use coal, natural gas, oil or nuclear materials as fuel~~regulating the management and ~~discharge treated effluent to surface waters as well as utility-owned landfills that receive~~disposal of coal combustion ~~residuals. Xcel Energy is currently reviewing~~byproducts (coal ash) as a nonhazardous waste. Under the final rule, Xcel Energy’s costs to manage and ~~cannot predict, at this time,~~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 United States Court of Appeals for the District of Columbia Circuit (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 early 2017 and a final decision is anticipated in the first half of 2017. Until a final decision is reached in the case, it is uncertain whether the ~~costs of compliance with the final rule~~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 believes that compliance costs would be recoverable through regulatory mechanisms.~~

~~Federal CWA Waters of the United States Rule~~ —In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The 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, as well as increasing project costs and expanding permitting and reporting requirements. The rule went into effect in August 2015. On Oct. 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule, pending further legal proceedings.Energy.

Air

~~Green House Gas (GHG) Emission Standard for Existing Sources~~ — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. A final rule was published in October 2015. States must develop implementation plans by September 2016, with the possibility of an extension to September 2018. If a state decides not to submit a plan, the EPA will prepare a federal plan for the state. In addition, the EPA published a proposed model federal plan and will provide a 90-day public comment period on the federal plan once it has been published in the Federal Register. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which Xcel Energy operates. Until Xcel Energy has reviewed the final rule and has more information about state implementation plans (SIPs), Xcel Energy cannot predict whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. Xcel Energy believes that compliance costs will be recoverable through regulatory mechanisms.

~~Table of Contents~~

~~GHG New Source Performance Standard (NSPS) Proposal~~ — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for natural gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The NSPS does not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. The final rule was published in October 2015. Xcel Energy does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows.

~~GHG NSPS for Modified and Reconstructed Power Plants~~ — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. A final rule was published in October 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The standards do not require installation of CCS technology. Instead, the standard for coal-fired power plants requires a combination of best operating practices and equipment upgrades. The standards for natural gas-fired power plants require emissions standards based on efficient combined cycle technology. These requirements would only apply if Xcel Energy were to modify or reconstruct an existing power plant in the future in a way that triggers applicability of this rule.

Cross-State Air Pollution Rule (CSAPR)— CSAPR addresses long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO₂) and ~~nitrous~~nitrogen 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,~~CSAPR was adopted to address interstate emissions impacting downwind states’ attainment of the ~~D.C. Circuit vacated~~1997 ozone National Ambient Air Quality Standard (NAAQS) and the ~~CSAPR~~1997 and ~~remanded it back to the EPA. The D.C. Circuit stated~~2006 particulate NAAQS. As the EPA ~~must continue administering~~revises the ~~Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement.~~NAAQS, it will consider whether to make any further reductions to CSAPR emission budgets and whether to change which states are included in the emissions trading program. 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 JulyDecember 2015, the ~~D.C. Circuit issued an opinion~~EPA proposed adjustments to CSAPR emission budgets which ~~found~~address attainment of 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~~more stringent 2008 ozone NAAQS. In September 2016 the EPA adopted a final rule that reduced the ozone season emission budget for NOx in Texas by approximately 22 percent, which is expected to ~~reconsider the~~lead to increased costs to purchase emission ~~budgets. While the EPA reconsiders~~allowances. Xcel Energy does not anticipate these increased costs to purchase 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~~allowances 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 not have a material impact on the results of operations, financial position or cash flows.

~~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. In June 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.

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~~Industrial Boiler (IB) Maximum Achievable Control Technology (MACT) Rules —~~ In 2011, the EPA finalized IB MACT rules to regulate boilers and process heaters fueled with coal, biomass and liquid fuels, which would apply to NSP-Wisconsin’s Bay Front Units 1 and 2. The project to meet the requirements was completed in September 2015 with an estimated cost of approximately $20 million.

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in ~~certain~~ national parks and wilderness areas. ~~In their first~~Under BART, regional haze ~~SIPs, Colorado, Minnesota and Texas identified the Xcel Energy~~plans identify facilities that will have to reduce SO₂, NOx and 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, CSAPR.

~~PSCo~~

In 2011, the Colorado Air Quality Control Commission approved a SIP (the Colorado SIP) that included the Clean Air Clean Jobs Act (CACJA) emission reduction plan as satisfying regional haze requirements for 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. Emission controls at Hayden Unit 1 and Hayden Unit 2 will be placed into service in late 2015 and late 2016, respectively, at an estimated combined cost of $82.4 million. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.

~~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. In September 2015, in response to a motion filed by WildEarth Guardians and the EPA, the 10^th ~~Circuit issued an order dismissing the case.~~

In 2010, two environmental groups petitioned the U.S. Department of the Interior (DOI) to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. The following PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege 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. In October 2014, the Eighth Circuit set a briefing schedule that was completed in February 2015. The Eighth Circuit heard arguments in September 2015 and a decision is anticipated in early 2016. 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.

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~~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~~substitution of CSAPR compliance for Texas’ reliance on CAIR. ~~The~~In January 2016, the EPA ~~has indicated that it expects to issue its~~adopted a final rule ~~in December 2015.~~

that defers its approval of CSAPR compliance as BART until the EPA considers further adjustments to CSAPR emission budgets under the D.C. Circuit’s remand of the Texas SO₂emission budgets. In ~~May 2014,~~March 2016, the EPA requested information under the Clean Air Act related to EGUs at SPS’ plants. SPS identified Harrington Units 1 and 2, Jones Units 1 and 2, Nichols Unit 3 and Plant X Unit 4 as BART-eligible units. These units will be evaluated based on their impact on visibility. Additional emission control equipment under the EPA’s BART guidelines for PM, SO₂ and NOx could be required if a unit is determined to “cause or contribute” to visibility impairment. SPS cannot evaluate the impact of additional emission controls until the EPA concludes its evaluation of BART. In June 2016, the EPA issued a ~~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~~and NOx emissions and rely on those emission budgets to satisfy Texas’ BART obligations under the regional haze rules. It is not yet known whether the Texas Commission on Environmental Quality (TCEQ) intends to utilize this option. If Texas does not opt into the CSAPR rule, the EPA is expected to issue a proposed rule in December 2016 that could impact Harrington Units 1 and 2.

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, which 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 or the costs of alternative cost-effective generation would be recoverable through regulatory mechanisms if required, and therefore does not expect a material impact on results of operations, financial position or cash flows.

~~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. In October 2015, the EPA proposed a rule that would set the agreed-upon SO~~₂ emission limits, which public comments due in November 2015. 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)~~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) made recommendations for unclassified and nonattainment areas to the EPA in September 2015. The EPA’s final decision is expected by summer 2016. Environment.

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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 or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.

~~Revisions~~In light of the continuing development of environmental regulatory requirements, as well as the more favorable long term outlook for alternative resources, SPS is undertaking analysis to determine the most cost-effective means to meet the needs of its customers, given a low natural gas price environment, the need to make additional investments to provide water to the ~~NAAQS for Ozone— In October 2015,~~Tolk facility and the ~~EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb)~~potential need to ~~70 ppb. In areas where Xcel Energy operates, current monitored~~make major investments in air quality concentrations comply with the new standard in the Twin Cities Metropolitan Area in Minnesota and meet the 70 ppb level in the Texas panhandle. In documents issued with the new standard, the EPA projects that both areas will meet the new standard. Current monitored air quality concentrations in areas of Wisconsin, where Xcel Energy operates, are also below the new standard. The Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent, standard. If not in attainment, impacted areas would study the sources of nonattainment and make emission reduction plans to attain the new standards. These plans would be due to the EPA in 2020. In conjunction with CACJA, Xcel Energy has or plans to shut down coal-fired plants in the Denver area, has installed NOx controls on Pawnee and Hayden Unit 1 and will finish installing NOx controls on Hayden Unit 2 in 2016. The final designation of nonattainment areas will be made in late 2017 based on air quality data years 2014-2016. Xcel Energy cannot evaluate the impacts of this ruling in Colorado until the designation of nonattainment areas is made and any required state plan has been developed. Xcel Energy believes that, should NOxpollution 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.equipment.

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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.

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~~under the Federal Power Act. The City of Seattle (the City) alleges between $34 million to $50 million in sales in the Pacific Northwest for December 2000 through June 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling, the FERC has allowed the parties to request additional evidence. Parties have claimed that the total amount of transactions with PSCo is subject to ~~refund is~~ ~~$34 million~~.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 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.

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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,~~May 2015, 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.~~

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.

~~Preliminary calculations~~In December 2015, the Ninth Circuit held that the standard of review applied by the FERC to the contracts which the City was challenging is appropriate. The Ninth Circuit dismissed questions concerning whether the FERC properly established the scope of the hearing, and determined that the challenged orders are preliminary and that the Ninth Circuit lacks jurisdiction to review evidentiary decisions until after the FERC’s proceedings are final. The City joined the State of ~~Seattle’s claim for refunds from PSCo~~California in its request seeking rehearing of this order, which the Ninth Circuit denied. The FERC proceedings are ~~approximately~~ ~~$28 million~~ ~~excluding interest. PSCo has concluded that a loss is reasonably possible~~now final with respect to ~~this matter; however, given~~ the ~~surrounding uncertainties, PSCo is currently unable~~City’s claims and are subject to ~~estimate the amount or range of reasonably possible loss~~review 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 thepending 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.~~appeal.

~~Biomass Fuel Handling Reimbursement —~~ NSP-Minnesota has a PPA through which it procures energy from Benson Power, LLC (Benson Power), as assignee of Fibrominn, LLC. Under this agreement, NSP-Minnesota is charged for certain costs of transporting biomass fuels that are delivered to Benson Power’s generation facility. Benson Power also sought additional cost reimbursement for certain transportation, handling and other costs incurred since 2007 totaling approximately $20 million. In ~~August 2015,~~October 2016, a settlement was reached ~~regarding~~that resolves all outstanding claims between and among the City and the respondents, including PSCo. Settlement terms required PSCo to pay the City $15,000 and the City to withdraw its pending appeal with the Ninth Circuit. This brings this ~~dispute. No loss was recorded related~~matter to ~~the terms of the settlement agreement.~~a close.

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

The cases were consolidated in U.S. District Court in Nevada. ~~In 2009, five~~Five of the cases ~~were~~have since been settled and ~~one was~~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 May 2016, the MDL judge granted summary judgment dismissing defendants from the Farmland lawsuit. e prime and Xcel Energy have filed a motion seeking clarification that this order includes them. This motion is currently pending and is expected to be heard in December 2016. The ~~U.S. District Court~~e prime defendants filed a summary judgment motion in ~~2011 issued an order dismissing entirely six of~~ the ~~remaining seven lawsuits,~~Colorado class lawsuit (Breckenridge) and ~~partially dismissing~~oppositions to class certifications in all the ~~seventh. Plaintiffs appealed the dismissals~~class actions, which is also expected to ~~the U.S. Court of Appeals for the Ninth Circuit, which reversed the District Court. The matter was ultimately~~be heard ~~by the U.S. Supreme Court~~ in early 2015, which agreed with the Ninth Circuit and remanded the matter to the U.S. District Court. In September 2015, the District Court held a status conference and set deadlines for certain litigation related activities inDecember 2016. ~~A trial date has not yet been set, but is~~Trial dates are not expected to occur prior to ~~late 2016 or~~ early 2017. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote.

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Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in Denver State Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric service agreements entered into by PSCo and various developers. The dispute involves assigned interests in those claims by over fifty developers. In May 2016, the district court granted PSCo’s motion to dismiss the lawsuit, concluding that jurisdiction over this dispute resides with the Colorado Public Utilities Commission (CPUC). In June 2016, DRC filed a notice of appeal. DRC filed its opening brief on Oct. 20, 2016 and PSCo’s answer brief is due Nov. 24, 2016. DRC also brought a proceeding before the CPUC as assignee on behalf of two developers, Ryland Homes and Richmond Homes of Colorado. In March 2016, the ALJ issued an order rejecting DRC’s claims for additional allowances and refunds. In June 2016, the ALJ’s determination was approved by the CPUC. DRC did not file a request for reconsideration before the CPUC contesting the decision, but filed an appeal in Denver District Court in August 2016.

PSCo has concluded that a loss is remote with respect to this ~~matter.~~

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~~Nuclear Power Operations~~matter as the service agreements were developed to implement CPUC approved tariffs and ~~Waste Disposal~~PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms. The amount or range in dispute is presently unknown and no accrual has been recorded for this matter.

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

~~In July 2011, the United States and NSP-Minnesota executed a settlement agreement resolving both lawsuits, providing an initial~~ ~~$100 million~~ payment from the United States to NSP-Minnesota, and providing a method by which NSP-Minnesota can recover its spent fuel storage costs through 2013. In January 2014, the United States proposed, 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 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 Sept. 30, 2015. In May 2015, NSP-Minnesota submitted a claim for an additional $13.2 million, and the DOE subsequently determined that NSP-Minnesota is entitled to reimbursement of $13.1 million. Payment of this amount is expected by the end of 2015. 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.

~~Other Commitments~~

~~Limited Partnership Investment~~ — In October 2015, Energy Impact Fund Investment, LLC (Energy Impact LLC), a wholly-owned non-utility subsidiary of Xcel Energy Inc., entered into a subscription agreement for a limited partnership interest, committing Energy Impact LLC to up to $50 million of total future investments in the newly formed Energy Impact Fund Limited Partnership (Energy Impact Fund LP) over the next five years. Along with the capital contributions of the other limited partners, who are primarily investor-owned utilities or their affiliates, the funding is expected to be used to make private equity investments in entities that are active developers and producers of new and emerging energy technologies applicable to utility operations, products and services. Xcel Energy expects to use the equity method to account for its interest in Energy Impact Fund LP.


7.	Borrowings and Other Financing Instruments

Short-Term Borrowings

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

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


(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2015			Twelve Months Ended Dec. 31, 2014			Three Months Ended Sept. 30, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	2,750		$	2,750		$	2,750		$	2,750
Amount outstanding at period end	64			1,020			366			846
Average amount outstanding	272			841			477			601
Maximum amount outstanding	478			1,200			609			1,360
Weighted average interest rate, computed on a daily basis	0.46		%	0.33		%	0.77		%	0.48		%
Weighted average interest rate at period end	0.38			0.56			0.77			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 Sept. 30, ~~2015~~2016 and Dec. 31, ~~2014,~~2015, there were ~~$39~~$19 million and ~~$61~~$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.

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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.

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At Sept. 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	$	64	$	936	$	1,000	$	362	$	638
PSCo	700		5		695		700		3		697
NSP-Minnesota	500		24		476		500		11		489
SPS	400		10		390		400		5		395
NSP-Wisconsin	150		—		150		150		4		146
Total	$	2,750	$	103	$	2,647	$	2,750	$	385	$	2,365


^(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 Sept. 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.

Long-Term Borrowings

During the nine months ended Sept. 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 ~~June, NSP-Wisconsin~~May, NSP-Minnesota issued ~~$100~~$350 million of ~~3.3~~3.6 percent first mortgage bonds due May 15, 2046;

In June, PSCo issued $250 million of 3.55 percent first mortgage bonds due June 15, ~~2024;~~2046; and

In August, ~~NSP-Minnesota~~SPS issued $300 million of ~~2.2~~3.4 percent first mortgage bonds due Aug. 15, ~~2020 and $300 million of 4.0 percent first mortgage bonds due Aug. 15, 2045; and~~

~~In September, SPS issued $200 million of 3.3 percent first mortgage bonds due June 15, 2024.~~2046.


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~~measurement date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

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

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

Specific valuation methods include the following:

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

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Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, international equity funds, private equity investments and real estate investments are measured using ~~net asset values,~~a 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~~

Table of ~~its redemption rights, fair value measurements for private equity and real estate investments have been assigned a Level 3.~~Contents

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

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

Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. 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.

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~~Nuclear Regulatory Commission (NRC) requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and ~~Prairie Island (PI)~~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.

~~Table of Contents~~

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 ~~$298.4~~$355.3 million and ~~$312.1~~$328.8 million at Sept. 30, ~~2015~~2016 and Dec. 31, ~~2014,~~2015, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were ~~$87.3~~$65.8 million and ~~$74.1~~$100.2 million at Sept. 30, ~~2015~~2016 and Dec. 31, ~~2014,~~2015, respectively.

Table of Contents

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


	Sept. 30, 2015										Sept. 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	$	33,681	$	33,681	$	—	$	—	$	33,681	$	15,055	$	15,055	$	—	$	—	$	—	$	15,055
Commingled funds	351,676		—		381,230		—		381,230
International equity funds	217,003		—		188,853		—		188,853
Commingled funds:
Non U.S. equities											254,362		—		—		—		245,481		245,481
Emerging market debt funds											92,472		—		—		—		101,387		101,387
Commodity funds											99,771		—		—		—		82,139		82,139
Private equity investments	98,133		—		—		145,695		145,695		130,848		—		—		—		178,768		178,768
Real estate	49,151		—		—		71,976		71,976		121,271		—		—		—		174,552		174,552
Other commingled funds											151,048		—		—		—		159,230		159,230
Debt securities:
Government securities	24,557		—		21,423		—		21,423		34,853		—		35,723		—		—		35,723
U.S. corporate bonds	70,311		—		61,874		—		61,874		95,828		—		93,981		—		—		93,981
International corporate bonds	14,099		—		13,059		—		13,059		19,877		—		19,860		—		—		19,860
Municipal bonds	210,728		—		215,014		—		215,014		13,906		—		14,638		—		—		14,638
Asset-backed securities	2,834		—		2,836		—		2,836		2,847		—		2,948		—		—		2,948
Mortgage-backed securities	11,734		—		12,077		—		12,077		10,118		—		10,582		—		—		10,582
Equity securities:
Common stock	386,176		533,431		—		—		533,431
U.S. equities											270,137		455,035		—		—		—		455,035
Non U.S. equities											213,291		225,782		—		—		—		225,782
Total	$	1,470,083	$	567,112	$	896,366	$	217,671	$	1,681,149	$	1,525,684	$	695,872	$	177,732	$	—	$	941,557	$	1,815,161


^(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes ~~$80.3~~$134.5 million of equity investments in unconsolidated subsidiaries and ~~$46.3~~$98.8 million of rabbi trust assets and miscellaneous investments.


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


	Dec. 31, 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
International equity funds	80,454		—		78,721		—		78,721
Commingled funds:
Non U.S. equities											259,114		—		—		—		231,122		231,122
Emerging market debt funds											88,987		—		—		—		88,467		88,467
Commodity funds											99,771		—		—		—		77,338		77,338
Private equity investments	73,936		—		—		101,237		101,237		105,965		—		—		—		157,528		157,528
Real estate	43,859		—		—		64,249		64,249		115,019		—		—		—		165,190		165,190
Other commingled funds											150,877		—		—		—		164,389		164,389
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
U.S. equities											273,106		432,495		—		—		—		432,495
Non U.S. equities											200,509		214,664		—		—		—		214,664
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.

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~~The following tables present~~For the ~~changes in~~nine months ended Sept. 30, 2016 and 2015 there were no Level 3 nuclear decommissioning fund investments ~~for the three~~ and ~~nine months ended Sept. 30, 2015 and 2014:~~no transfers of amounts between levels.

(Thousands of Dollars) July 1, 2015 Purchases Settlements
Gains Recognized as
Regulatory Assets ^(a)
Sept. 30, 2015
Private equity investments $ 133,993
$ 3,066
$ —
$ 8,636
$ 145,695
Real estate 70,834
1,501
(1,719 ) 1,360
71,976
Total $ 204,827
$ 4,567
$ (1,719 ) $ 9,996
$ 217,671

(Thousands of Dollars) July 1, 2014 Purchases Settlements
Gains Recognized as
Regulatory Asset ^(a)
Sept. 30, 2014
Private equity investments $ 81,123
$ 11,125
$ —
$ 4,756
$ 97,004
Real estate 65,658
1,530
(5,876 ) 2,661
63,973
Total $ 146,781
$ 12,655
$ (5,876 ) $ 7,417
$ 160,977

(Thousands of Dollars) Jan. 1, 2015 Purchases Settlements
Gains Recognized as
Regulatory Assets ^(a)
Sept. 30, 2015
Private equity investments $ 101,237
$ 24,197
$ —
$ 20,261
$ 145,695
Real estate 64,249
9,633
(4,341 ) 2,435
71,976
Total $ 165,486
$ 33,830
$ (4,341 ) $ 22,696
$ 217,671

(Thousands of Dollars) Jan. 1, 2014 Purchases Settlements
Gains Recognized as
Regulatory Asset ^(a)
Sept. 30, 2014
Private equity investments $ 62,696
$ 22,078
$ —
$ 12,230
$ 97,004
Real estate 57,368
5,386
(5,876 ) 7,095
63,973
Total $ 120,064
$ 27,464
$ (5,876 ) $ 19,325
$ 160,977


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

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at Sept. 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	$	—	$	—	$	—	$	21,423		$	21,423	$	—	$	10,583	$	971	$	24,169	$	35,723
U.S. corporate bonds	—		15,398		51,317		(4,841		)	61,874		257		28,245		59,451		6,028		93,981
International corporate bonds	—		2,976		9,109		974			13,059		—		5,043		11,606		3,211		19,860
Municipal bonds	1,260		27,500		44,594		141,660			215,014		—		210		5,773		8,655		14,638
Asset-backed securities	—		—		2,836		—			2,836		—		—		2,948		—		2,948
Mortgage-backed securities	—		—		—		12,077			12,077		—		—		—		10,582		10,582
Debt securities	$	1,260	$	45,874	$	107,856	$	171,293		$	326,283	$	257	$	44,081	$	80,749	$	52,645	$	177,732

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 Sept. 30, 2016:



	Sept. 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	1,594		1,867		—		—		1,867
Total	$	49,356	$	49,629	$	—	$	—	$	49,629


^(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.

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At Sept. 30, ~~2015,~~2016, accumulated other comprehensive losses related to interest rate derivatives included ~~$3.7~~$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.

At Sept. 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 nine months ended Sept. 30, ~~2015~~2016 and ~~2014.~~2015.

At Sept. 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~~immaterial 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.

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


(Amounts in Thousands) ^(a)(b)	Sept. 30, 2015	Dec. 31, 2014	Sept. 30, 2016	Dec. 31, 2015
Megawatt hours of electricity	76,323	56,361	64,040	50,487
Million British thermal units of natural gas	13,709	927	116,144	20,874
Gallons of vehicle fuel	176	282	35	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.

Table of Contents

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


	Three Months Ended Sept. 30, 2015																	Three Months Ended Sept. 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 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													Pre-Tax Losses Recognized During the Period in Income
Interest rate	$	—		$	—		$	1,118	^(a)	$	—		$	—				$	—			$	—			$	1,502	^(a)	$	—		$	—
Vehicle fuel and other commodity	(70		)	—			34		^(b)	—			—					(6		)		—				46		^(b)	—			—
Total	$	(70	)	$	—		$	1,152		$	—		$	—				$	(6	)		$	—			$	1,548		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	(3,460	)	^(c)		$	—			$	—			$	—		$	—		$	1,779		^(c)
Electric commodity	—			(2,403		)	—			2,860		^(d)	—					—				15,497				—			2,491		^(d)	—
Natural gas commodity	—			(2,978		)	—			—			(405		)	^(e)		—				(5,737		)		—			—			(6		)	^(e)
Total	$	—		$	(5,381	)	$	—		$	2,860		$	(3,865	)			$	—			$	9,760			$	—		$	2,491		$	1,773



	Nine Months Ended Sept. 30, 2016
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	4,470	^(a)	$	—		$	—
Vehicle fuel and other commodity	7		—			150		^(b)	—			—
Total	$	7	$	—		$	4,620		$	—		$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—		$	3,269		^(c)
Electric commodity	—		14,528			—			30,024		^(d)	—
Natural gas commodity	—		(2,376		)	—			11,666		^(e)	(5,005		)	^(e)
Total	$	—	$	12,152		$	—		$	41,690		$	(1,736	)



	Three Months Ended Sept. 30, 2015
	Pre-Tax Fair Value Losses Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Losses Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)			Pre-Tax Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	1,118	^(a)	$	—		$	—
Vehicle fuel and other commodity	(70		)	—			34		^(b)	—			—
Total	$	(70	)	$	—		$	1,152		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	(3,460	)	^(c)
Electric commodity	—			(2,403		)	—			2,860		^(d)	—
Natural gas commodity	—			(2,978		)	—			—			(405		)	^(e)
Total	$	—		$	(5,381	)	$	—		$	2,860		$	(3,865	)

Table of Contents

Nine Months Ended Sept. 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 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 $ —
$ —
$ 3,013
^(a)
$ —
$ —

Vehicle fuel and other commodity (59 ) —
88
^(b)
—
—

Total $ (59 ) $ —
$ 3,101
$ —
$ —

Other derivative instruments
Commodity trading $ —
$ —
$ —
$ —
$ (5,896 )
^(c)
Electric commodity —
(16,611 ) —
16,020
^(d)
—

Natural gas commodity —
(3,366 ) —
8,685
^(e)
(9,455 )
^(e)
Total $ —
$ (19,977 ) $ —
$ 24,705
$ (15,351 )

Three Months Ended Sept. 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 $ —
$ —
$ 967
^(a)
$ —
$ —

Vehicle fuel and other commodity (69 ) —
(16 )
^(b)
—
—

Total $ (69 ) $ —
$ 951
$ —
$ —

Other derivative instruments
Commodity trading $ —
$ —
$ —
$ —
$ (1,656 )
^(c)
Electric commodity —
(3,391 ) —
6,629
^(d)
—

Natural gas commodity —
(2,455 ) —
—
(209 )
^(d)
Total $ —
$ (5,846 ) $ —
$ 6,629
$ (1,865 )

~~Table of Contents~~


	Nine Months Ended Sept. 30, 2014																			Nine Months Ended Sept. 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 (Losses) Recognized During the Period in Income					Pre-Tax Fair Value Losses Recognized During the Period in:								Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Losses Recognized During the Period in Income
(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 Losses Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	2,869		^(a)	$	—			$	—				$	—			$	—			$	3,013	^(a)	$	—		$	—
Vehicle fuel and other commodity	(56		)	—			(61		)	^(b)	—				—					(59		)		—				88		^(b)	—			—
Total	$	(56	)	$	—		$	2,808			$	—			$	—				$	(59	)		$	—			$	3,101		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—			$	—			$	1,266		^(c)		$	—			$	—			$	—		$	—		$	(5,896	)	^(c)
Electric commodity	—			(17,240		)	—				(18,641		)	^(d)	—					—				(16,611		)		—			16,020		^(d)	—
Natural gas commodity	—			13,603			—				(18,840		)	^(e)	(5,575		)	^(e)		—				(3,366		)		—			8,685		^(e)	(9,455		)	^(e)
Other commodity	—			—			—				—				643			^(c)
Total	$	—		$	(3,637	)	$	—			$	(37,481	)		$	(3,666	)			$	—			$	(19,977	)		$	—		$	24,705		$	(15,351	)


^(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 nine months ended Sept. 30, ~~2015~~2016 included ~~$0.4 million and $0.5 million, respectively, of~~no settlement gains or 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. ~~Losses~~Amounts for the three and nine months ended Sept. 30, ~~2014~~2015 included ~~immaterial~~$0.4 million and $0.5 million, respectively, 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 nine months ended Sept. 30, ~~2015~~2016 and ~~nine 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.

Xcel Energy had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 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.

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 Sept. 30, ~~2015, three~~2016, one of Xcel Energy’s 10 most significant counterparties for these activities, comprising ~~$24.7~~$14.1 million or 106 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. ~~Five~~Nine of the 10 most significant counterparties, comprising ~~$61.1~~$73.4 million or 2633 percent of this credit exposure, were not rated by these external agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. The remaining two most significant counterparties, comprising $11.5 million or 5 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external and internal analysis. All 10ten of these significant counterparties are RTOs, municipal or cooperative electric entities or other utilities.

~~Table of Contents~~

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. If the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment grade, derivative instruments reflected in a $8.9 million gross liability position on the consolidated balance sheet atAt Sept. 30, 2015 would have required Xcel Energy Inc.’s utility subsidiaries to post collateral or settle applicable outstanding contracts, including other contracts subject to master netting agreements, which would have resulted in payments of $0.1 million. At2016 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.

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


	Sept. 30, 2015														Sept. 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	$	—	$	9,140	$	4,307	$	13,447	$	(5,150	)		$	8,297	$	3,846	$	11,239	$	—	$	15,085	$	(9,440	)	$	5,645
Electric commodity	—		—		34,715		34,715		(6,361		)		28,354		—		—		27,775		27,775		(3,180		)	24,595
Natural gas commodity	—		3,062		—		3,062		(1,690		)		1,372		—		6,034		—		6,034		(15		)	6,019
Total current derivative assets	$	—	$	12,202	$	39,022	$	51,224	$	(13,201	)		38,023		$	3,846	$	17,273	$	27,775	$	48,894	$	(12,635	)	36,259
PPAs ^(a)													10,087													6,601
Current derivative instruments													$	48,110												$	42,860
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	—	$	29,523	$	—	$	29,523	$	(7,411	)		$	22,112	$	501	$	32,538	$	—	$	33,039	$	(8,306	)	$	24,733
Natural gas commodity															—		681		—		681		—			681
Total noncurrent derivative assets	$	—	$	29,523	$	—	$	29,523	$	(7,411	)		22,112		$	501	$	33,219	$	—	$	33,720	$	(8,306	)	25,414
PPAs ^(a)													32,631													25,955
Noncurrent derivative instruments													$	54,743												$	51,369

~~Table of Contents~~


	Sept. 30, 2015														Sept. 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	$	—	$	156	$	—	$	156	$	—			$	156	$	—	$	41	$	—	$	41	$	—		$	41
Other derivative instruments:
Commodity trading	—		6,461		1,478		7,939		(5,592		)		2,347		3,921		8,000		—		11,921		(9,527		)	2,394
Electric commodity	—		—		6,361		6,361		(6,361		)		—		—		—		3,180		3,180		(3,180		)	—
Natural gas commodity	—		2,777		—		2,777		(1,690		)		1,087		—		15		—		15		(15		)	—
Other commodity	—		844		—		844		—				844
Total current derivative liabilities	$	—	$	10,238	$	7,839	$	18,077	$	(13,643	)		4,434		$	3,921	$	8,056	$	3,180	$	15,157	$	(12,722	)	2,435
PPAs ^(a)													22,869													22,766
Current derivative instruments													$	27,303												$	25,201
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	36	$	—	$	36	$	—			$	36
Other derivative instruments:
Commodity trading	—		20,789		—		20,789		(11,097		)		9,692		$	538	$	24,114	$	—	$	24,652	$	(11,005	)	$	13,647
Other commodity	—		18		—		18		—				18
Total noncurrent derivative liabilities	$	—	$	20,843	$	—	$	20,843	$	(11,097	)		9,746		$	538	$	24,114	$	—	$	24,652	$	(11,005	)	13,647
PPAs ^(a)													163,842													141,003
Noncurrent derivative instruments													$	173,588												$	154,650

^(a)

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

^(b)

Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, ~~2015.~~2016. At Sept. 30, ~~2015,~~2016, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of ~~$4.1~~$2.8 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.

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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

~~Table of Contents~~


	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~~$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.

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

Three Months Ended Sept. 30
(Thousands of Dollars) 2015 2014
Balance at July 1 $ 46,826
$ 105,394
Purchases 486
5,588
Settlements (20,216 ) (20,032 )
Transfers out of Level 3 —
(1,093 )
Net transactions recorded during the period:
Gains recognized in earnings ^(a)
121
1,480
Gains (losses) recognized as regulatory assets and liabilities 3,966
(17,705 )
Balance at Sept. 30 $ 31,183
$ 73,632

~~Table of Contents~~



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

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

Nine Months Ended Sept. 30
(Thousands of Dollars) 2015 2014
Balance at Jan. 1 $ 56,155
$ 41,660
Purchases 63,724
126,752
Settlements (57,462 ) (107,451 )
Transfers out of Level 3 —
(1,093 )
Net transactions recorded during the period:
Gains recognized in earnings ^(a)
1,401
8,917
(Losses) gains recognized as regulatory assets and liabilities (32,635 ) 4,847
Balance at Sept. 30 $ 31,183
$ 73,632


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

Xcel Energy recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and nine months ended Sept. 30, ~~2015. The transfer of amounts from Level 3 to Level 2 in the three~~2016 and ~~nine months ended Sept. 30, 2014 was due to the valuation of certain long-term derivative contracts for which observable commodity pricing forecasts became a more significant input during the period.~~2015.

Fair Value of Long-Term Debt

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


	Sept. 30, 2015				Dec. 31, 2014				Sept. 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)	$	13,148,225	$	14,304,149	$	11,757,360	$	13,360,236	$	14,112,150	$	16,127,060	$	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 Sept. 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 Sept. 30					Nine Months Ended Sept. 30						Three Months Ended Sept. 30					Nine Months Ended Sept. 30
(Thousands of Dollars)	2015		2014			2015			2014			2016			2015		2016			2015
Interest income	$	312	$	1,139		$	4,939		$	6,324		$	1,385		$	312	$	6,439		$	4,939
Other nonoperating income	625		682			2,387			3,042			341			625		2,517			2,387
Insurance policy income (expense)	689		(417		)	(1,578		)	(4,663		)
Other nonoperating expense	—		—			—			(16		)
Insurance policy (expense) income												(1,148		)	689		(2,568		)	(1,578		)
Other income, net	$	1,626	$	1,404		$	5,748		$	4,687		$	578		$	1,626	$	6,388		$	5,748


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.

~~Table of Contents~~

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 ~~$80.3~~$134.5 million and ~~$83.1~~$130.0 million as of Sept. 30, ~~2015~~2016 and Dec. 31, ~~2014,~~2015, respectively, included in the regulated natural gas utility segment.

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

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



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



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


(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total		Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Three Months Ended Sept. 30, 2014
Nine Months Ended Sept. 30, 2016
Operating revenues from external customers	$	2,616,351	$	236,649	$	16,807	$	—		$	2,869,807	$	7,209,225	$	1,046,544	$	56,500		$	—		$	8,312,269
Intersegment revenues	472		597		—		(1,069		)	—		1,038		820		—			(1,858		)	—
Total revenues	$	2,616,823	$	237,246	$	16,807	$	(1,069	)	$	2,869,807	$	7,210,263	$	1,047,364	$	56,500		$	(1,858	)	$	8,312,269
Net income	$	360,656	$	3,996	$	3,930	$	—		$	368,582
Net income (loss)												$	863,076	$	84,974	$	(52,148	)	$	—		$	895,902

(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total
Nine Months Ended Sept. 30, 2015
Operating revenues from external customers ^(a)
$ 7,105,803
$ 1,216,146
$ 56,716
$ —
$ 8,378,665
Intersegment revenues 1,142
1,141
—
(2,283 ) —
Total revenues $ 7,106,945
$ 1,217,287
$ 56,716
$ (2,283 ) $ 8,378,665
Net income (loss) $ 733,954
^(a)
$ 72,617
$ (31,111 ) $ —
$ 775,460
32

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(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total
Nine Months Ended Sept. 30, 2014
Operating revenues from external customers $ 7,215,699
$ 1,485,464
$ 56,344
$ —
$ 8,757,507
Intersegment revenues 1,262
4,967
—
(6,229 ) —
Total revenues $ 7,216,961
$ 1,490,431
$ 56,344
$ (6,229 ) $ 8,757,507
Net income (loss) $ 731,766
$ 96,629
$ (3,428 ) $ —
$ 824,967



(Thousands of Dollars)	Regulated Electric			Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
Nine Months Ended Sept. 30, 2015
Operating revenues from external customers	$	7,105,803		$	1,216,146	$	56,716		$	—		$	8,378,665
Intersegment revenues	1,142			1,141		—			(2,283		)	—
Total revenues	$	7,106,945		$	1,217,287	$	56,716		$	(2,283	)	$	8,378,665
Net income (loss)	$	733,954	^(a)	$	72,617	$	(31,111	)	$	—		$	775,460


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

~~Table of Contents~~


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.

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 Sept. 30, 2015					Three Months Ended Sept. 30, 2014					Three Months Ended Sept. 30, 2016					Three Months Ended Sept. 30, 2015
(Amounts in thousands, except per share data)	Income		Shares	Per Share Amount		Income		Shares	Per Share Amount		Income		Shares	Per Share Amount		Income		Shares	Per Share Amount
Net income	$	426,463	—	—		$	368,582	—	—		$	457,795	—	—		$	426,463	—	—
Basic EPS:
Earnings available to common shareholders	426,463		508,031	$	0.84	368,582		506,082	$	0.73	457,795		508,941	$	0.90	426,463		508,031	$	0.84
Effect of dilutive securities:
Time based equity awards	—		396	—		—		283	—		—		625	—		—		396	—
Diluted EPS:
Earnings available to common shareholders	$	426,463	508,427	$	0.84	$	368,582	506,365	$	0.73	$	457,795	509,566	$	0.90	$	426,463	508,427	$	0.84

Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014
(Amounts in thousands, except per share data) Income Shares
Per Share
Amount
Income Shares
Per Share
Amount
Net income $ 775,460

—
$ 824,967
—
—
Basic EPS:
Earnings available to common shareholders 775,460
507,585
$ 1.53
824,967
502,983
$ 1.64
Effect of dilutive securities:
Time based equity awards —
391
—
—
230
—
Diluted EPS:
Earnings available to common shareholders $ 775,460
507,976
$ 1.53
$ 824,967
503,213
$ 1.64

4033

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	Nine Months Ended Sept. 30, 2016					Nine Months Ended Sept. 30, 2015
(Amounts in thousands, except per share data)	Income		Shares	Per Share Amount		Income		Shares	Per Share Amount
Net income	$	895,902	—	—		$	775,460	—	—
Basic EPS:
Earnings available to common shareholders	895,902		508,840	$	1.76	775,460		507,585	$	1.53
Effect of dilutive securities:
Time based equity awards	—		556	—		—		391	—
Diluted EPS:
Earnings available to common shareholders	$	895,902	509,396	$	1.76	$	775,460	507,976	$	1.53


12.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)


	Three Months Ended Sept. 30												Three Months Ended Sept. 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		$	22,086		$	529		$	864		$	22,940		$	24,828		$	432		$	529
Interest cost	37,131			39,155			6,324			8,507			40,027			37,131			6,527			6,324
Expected return on plan assets	(53,473		)	(51,801		)	(6,650		)	(8,489		)	(52,575		)	(53,473		)	(6,249		)	(6,650		)
Amortization of prior service credit	(451		)	(437		)	(2,672		)	(2,672		)	(478		)	(451		)	(2,672		)	(2,672		)
Amortization of net loss	31,288			29,191			1,351			2,935			24,384			31,288			1,011			1,351
Net periodic benefit cost (credit)	39,323			38,194			(1,118		)	1,145			34,298			39,323			(951		)	(1,118		)
Costs not recognized due to the effects of regulation	(7,016		)	(6,605		)	—			—			(3,976		)	(7,016		)	—			—
Net benefit cost (credit) recognized for financial reporting	$	32,307		$	31,589		$	(1,118	)	$	1,145		$	30,322		$	32,307		$	(951	)	$	(1,118	)


	Nine Months Ended Sept. 30												Nine Months Ended Sept. 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	$	74,484		$	66,257		$	1,587		$	2,592		$	68,805		$	74,484		$	1,295		$	1,587
Interest cost	111,393			117,465			18,972			25,521			120,078			111,393			19,580			18,972
Expected return on plan assets	(160,418		)	(155,403		)	(19,950		)	(25,466		)	(157,725		)	(160,418		)	(18,746		)	(19,950		)
Amortization of prior service credit	(1,353		)	(1,310		)	(8,015		)	(8,016		)	(1,439		)	(1,353		)	(8,015		)	(8,015		)
Amortization of net loss	93,864			87,572			4,053			8,805			73,154			93,864			3,031			4,053
Net periodic benefit cost (credit)	117,970			114,581			(3,353		)	3,436			102,873			117,970			(2,855		)	(3,353		)
Costs not recognized due to the effects of regulation	(22,035		)	(20,261		)	—			—			(12,587		)	(22,035		)	—			—
Net benefit cost (credit) recognized for financial reporting	$	95,935		$	94,320		$	(3,353	)	$	3,436		$	90,286		$	95,935		$	(2,855	)	$	(3,353	)

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.

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13.	Other Comprehensive Income

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



	Three Months Ended Sept. 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at July 1	$	(52,980	)	$	110	$	(53,925	)	$	(106,795	)
Other comprehensive loss before reclassifications	(4		)	—		—			(4		)
Losses reclassified from net accumulated other comprehensive loss	960			—		878			1,838
Net current period other comprehensive income	956			—		878			1,834
Accumulated other comprehensive (loss) income at Sept. 30	$	(52,024	)	$	110	$	(53,047	)	$	(104,961	)



	Three Months Ended Sept. 30, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at July 1	$	(56,436	)	$	112		$	(48,862	)	$	(105,186	)
Other comprehensive loss before reclassifications	(42		)	(1		)	—			(43		)
Losses reclassified from net accumulated other comprehensive loss	706			—			884			1,590
Net current period other comprehensive income (loss)	664			(1		)	884			1,547
Accumulated other comprehensive (loss) income at Sept. 30	$	(55,772	)	$	111		$	(47,978	)	$	(103,639	)



	Nine Months Ended Sept. 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities		Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive (loss) income at Jan. 1	$	(54,862	)	$	110	$	(55,001	)	$	(109,753	)
Other comprehensive income (loss) before reclassifications	4			—		(653		)	(649		)
Losses reclassified from net accumulated other comprehensive loss	2,834			—		2,607			5,441
Net current period other comprehensive income	2,838			—		1,954			4,792
Accumulated other comprehensive (loss) income at Sept. 30	$	(52,024	)	$	110	$	(53,047	)	$	(104,961	)



	Nine Months Ended Sept. 30, 2015
(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 (loss) income before reclassifications	(35		)	1		—			(34		)
Losses reclassified from net accumulated other comprehensive loss	1,891			—		2,643			4,534
Net current period other comprehensive income	1,856			1		2,643			4,500
Accumulated other comprehensive (loss) income at Sept. 30	$	(55,772	)	$	111	$	(47,978	)	$	(103,639	)

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Three Months Ended Sept. 30, 2014
(Thousands of Dollars)
Gains and Losses
on Cash Flow Hedges

Unrealized Gains and Losses
on Marketable Securities
Defined Benefit Pension and
Postretirement Items Total
Accumulated other comprehensive (loss) income at July 1 $ (58,610 ) $ 115
$ (44,871 ) $ (103,366 )
Other comprehensive (loss) income before reclassifications (42 ) 2
—
(40 )
Losses reclassified from net accumulated other comprehensive loss 558
—
847
1,405
Net current period other comprehensive income 516
2
847
1,365
Accumulated other comprehensive (loss) income at Sept. 30 $ (58,094 ) $ 117
$ (44,024 ) $ (102,001 )

Nine Months Ended Sept. 30, 2015
(Thousands of Dollars)
Gains and Losses
on Cash Flow Hedges

Unrealized Gains and Losses
on Marketable Securities

Defined Benefit Pension and
Postretirement Items
Total
Accumulated other comprehensive (loss) income at Jan. 1 $ (57,628 ) $ 110
$ (50,621 ) $ (108,139 )
Other comprehensive (loss) income before reclassifications (35 ) 1
—
(34 )
Losses reclassified from net accumulated other comprehensive loss 1,891
—
2,643
4,534
Net current period other comprehensive income 1,856
1
2,643
4,500
Accumulated other comprehensive (loss) income at Sept. 30 $ (55,772 ) $ 111
$ (47,978 ) $ (103,639 )

Nine Months Ended Sept. 30, 2014
(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 $ (59,753 ) $ 77
$ (46,599 ) $ (106,275 )
Other comprehensive (loss) income before reclassifications (34 ) 40
—
6
Losses reclassified from net accumulated other comprehensive loss 1,693
—
2,575
4,268
Net current period other comprehensive income 1,659
40
2,575
4,274
Accumulated other comprehensive (loss) income at Sept. 30 $ (58,094 ) $ 117
$ (44,024 ) $ (102,001 )

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 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 Sept. 30, 2015				Three Months Ended Sept. 30, 2014				Three Months Ended Sept. 30, 2016				Three Months Ended Sept. 30, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	1,118		^(a)	$	967		^(a)	$	1,502		^(a)	$	1,118		^(a)
Vehicle fuel derivatives	34			^(b)	(16		)	^(b)	46			^(b)	34			^(b)
Total, pre-tax	1,152				951				1,548				1,152
Tax benefit	(446		)		(393		)		(588		)		(446		)
Total, net of tax	706				558				960				706
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	1,532			^(c)	1,500			^(c)	1,478			^(c)	1,532			^(c)
Prior service credit	(89		)	^(c)	(86		)	^(c)	(64		)	^(c)	(89		)	^(c)
Total, pre-tax	1,443				1,414				1,414				1,443
Tax benefit	(559		)		(567		)		(536		)		(559		)
Total, net of tax	884				847				878				884
Total amounts reclassified, net of tax	$	1,590			$	1,405			$	1,838			$	1,590

~~Table of Contents~~


	Amounts Reclassified from Accumulated Other Comprehensive Loss								Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2015				Nine Months Ended Sept. 30, 2014				Nine Months Ended Sept. 30, 2016				Nine Months Ended Sept. 30, 2015
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	3,013		^(a)	$	2,869		^(a)	$	4,470		^(a)	$	3,013		^(a)
Vehicle fuel derivatives	88			^(b)	(61		)	^(b)	150			^(b)	88			^(b)
Total, pre-tax	3,101				2,808				4,620				3,101
Tax benefit	(1,210		)		(1,115		)		(1,786		)		(1,210		)
Total, net of tax	1,891				1,693				2,834				1,891
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss	4,600			^(c)	4,499			^(c)	4,434			^(c)	4,600			^(c)
Prior service (credit) cost	(268		)	^(c)	(258		)	^(c)
Prior service credit									(192		)	^(c)	(268		)	^(c)
Total, pre-tax	4,332				4,241				4,242				4,332
Tax benefit	(1,689		)		(1,666		)		(1,635		)		(1,689		)
Total, net of tax	2,643				2,575				2,607				2,643
Total amounts reclassified, net of tax	$	4,534			$	4,268			$	5,441			$	4,534


^(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.

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

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

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Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including ~~the 2015~~our 2016 and ~~2016~~2017 earnings per share guidance and assumptions, are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly ~~Reports~~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, ~~2014~~2015 and Quarterly Reports on Form 10-Q for the quarters ended March 31, ~~2015~~2016 and June 30, ~~2015)~~2016), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a slow down in the U.S. economy or delay in growth, ~~recovery;~~recovery, trade, fiscal, taxation and environmental policies in areas where Xcel Energy has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors including the extent and timing of the entry of additional competition in the markets served by Xcel Energy and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ~~ownership;~~ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability of cost of capital; and employee work force 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.

Results of Operations

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


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended Sept. 30						Nine Months Ended Sept. 30
Diluted Earnings (Loss) Per Share	2015			2014			2015			2014			2016			2015			2016			2015
PSCo	$	0.34		$	0.30		$	0.75		$	0.72		$	0.34		$	0.34		$	0.74		$	0.75
NSP-Minnesota	0.35			0.27			0.65			0.63			0.41			0.35			0.74			0.65
SPS	0.12			0.13			0.21			0.23			0.13			0.12			0.24			0.21
NSP-Wisconsin	0.05			0.04			0.13			0.11			0.05			0.05			0.11			0.13
Equity earnings of unconsolidated subsidiaries	0.01			0.01			0.03			0.03			0.01			0.01			0.04			0.03
Regulated utility	0.87			0.75			1.77			1.72			0.94			0.87			1.87			1.77
Xcel Energy Inc. and other	(0.03		)	(0.02		)	(0.08		)	(0.08		)	(0.04		)	(0.03		)	(0.11		)	(0.08		)
Ongoing diluted EPS	0.84			0.73			1.69			1.64			0.90			0.84			1.76			1.69
Loss on Monticello LCM/EPU project	—			—			(0.16		)	—			—			—			—			(0.16		)
GAAP diluted EPS	$	0.84		$	0.73		$	1.53		$	1.64		$	0.90		$	0.84		$	1.76		$	1.53

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Earnings Adjusted for Certain Items (Ongoing Earnings)

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

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

Summary of Ongoing Earnings

Xcel Energy — Xcel Energy’s ongoing earnings increased ~~$0.11~~$0.06 for the third quarter of ~~2015~~2016 and ~~$0.05~~$0.07 per share year-to-date, which excludes anthe 2015 adjustment for a charge related to the NSP-Minnesota Monticello LCM/EPU project. Electric and natural gas margins rose in the third quarter primarily driven by higher retail electric and natural gas rates and non-fuel riders to recover our capital investments, along with higher sales growth. These positive factors and a lower effective tax rate were offset by higher depreciation, operating and maintenance expenses and interest charges.

PSCo— PSCo’s ongoing earnings were flat for the third quarter of ~~2015~~2016 and decreased $0.01 per share year-to-date. Year-to-date, higher natural gas margins, primarily due to rate increases, and higher AFUDC were offset by higher depreciation, O&M expenses and interest charges.

NSP-Minnesota— NSP-Minnesota’s ongoing earnings increased $0.06 for the third quarter of 2016 and $0.09 per share year-to-date. Year-to-date, higher electric revenues driven by an interim electric rate increase in ~~retail electric rates,~~Minnesota (subject to refund) and non-fuel riders ~~the impact of favorable weather and a lower earnings test refund in Colorado. These positive factors~~ were partially offset by higher depreciation, ~~and~~O&M expenses, interest charges ~~lower AFUDC~~ and ~~increased~~ property taxes.

~~PSCo~~SPS— ~~— PSCo’s~~SPS’ ongoing earnings increased ~~$0.04 per share~~$0.01 for the third quarter of ~~2015~~2016 and $0.03 per share year-to-date. ~~Higher revenue primarily due to the CACJA rider (partially offset by an~~Year-to-date, higher electric ~~base rate decrease),~~margins and lower ~~estimated electric earnings test refunds and the impact of favorable weather~~O&M expenses were partially offset by ~~lower AFUDC, higher property taxes, depreciation and O&M expenses.~~an increase in depreciation.

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

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

4438

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~~NSP-Minnesota~~ — NSP-Minnesota’s ongoing earnings increased $0.08 per share for the third quarter of 2015 and $0.02 year-to-date. Revenues increased primarily due to electric rate cases in Minnesota, North Dakota and South Dakota and were partially offset by higher depreciation, higher O&M expenses, lower gas margins, higher interest charges, unfavorable weather and weather-normalized sales decline.

~~SPS~~ — SPS’ ongoing earnings decreased $0.01 per share for the third quarter of 2015 and $0.02 year-to-date. Higher electric rates in Texas were more than offset by higher O&M expenses, increased depreciation, lower AFUDC and higher interest charges and unfavorable weather.

~~NSP-Wisconsin~~ — NSP-Wisconsin’s ongoing earnings per share increased $0.01 for the third quarter of 2015 and $0.02 year-to-date. Higher electric margins, primarily due to an electric rate increase and weather-normalized sales growth and lower O&M expenses were partially offset by higher depreciation and unfavorable weather.

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 Sept. 30 Nine Months Ended Sept. 30
2014 GAAP and ongoing diluted EPS $ 0.73
$ 1.64

Components of change — 2015 vs. 2014
Higher electric margins 0.14
0.25
Lower conservation and DSM program expenses (offset by lower revenues) 0.02
0.07
Higher depreciation and amortization (0.03 ) (0.09 )
Lower AFUDC — equity (0.02 ) (0.06 )
Higher O&M expenses —
(0.04 )
Higher taxes (other than income taxes) (0.01 ) (0.04 )
Higher ETR (0.01 ) (0.03 )
Higher interest charges (0.01 ) (0.02 )
Dilution from equity issued through the direct stock purchase plan and benefit plans —
(0.02 )
Higher natural gas margins 0.02
—
Other, net 0.01
0.03
2015 ongoing diluted EPS 0.84
1.69
Loss on Monticello LCM/EPU project —
(0.16 )
2015 GAAP diluted EPS $ 0.84
$ 1.53



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

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

~~The following tables summarize~~^(a)Reflects $0.006 and $0.015 attributable to weather for the ~~earnings contributions of Xcel Energy’s business segments:~~three and nine months ended Sept. 30, 2016, respectively.

Three Months Ended Sept. 30 Nine Months Ended Sept. 30
(Millions of Dollars) 2015 2014 2015 2014
GAAP income (loss) by segment
Regulated electric income $ 438.0
$ 360.7
$ 734.0
$ 731.8
Regulated natural gas (loss) income (4.2 ) 4.0
72.6
96.6
Other income ^(a)
7.7
15.2
10.0
35.4
Xcel Energy Inc. and other ^(a)
(15.0 ) (11.3 ) (41.1 ) (38.8 )
Total net income $ 426.5
$ 368.6
$ 775.5
$ 825.0

~~Table of Contents~~

Three Months Ended Sept. 30 Nine Months Ended Sept. 30
Contributions to Diluted Earnings (Loss) Per Share 2015 2014 2015 2014
GAAP earnings (loss) by segment
Regulated electric $ 0.86
$ 0.71
$ 1.45
$ 1.46
Regulated natural gas (0.01 ) 0.01
0.14
0.19
Other ^(a)
0.02
0.03
0.02
0.07
Xcel Energy Inc. and other ^(a)
(0.03 ) (0.02 ) (0.08 ) (0.08 )
Total diluted EPS $ 0.84
$ 0.73
$ 1.53
$ 1.64


^(a)^(b)Reflects $0.001 and $(0.007) attributable to weather for the three and nine months ended Sept. 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.

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


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended Sept. 30						Nine Months Ended Sept. 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	(57.9	)%	(11.2	)%	(54.8	)%	(4.2	)%	11.5	%	(14.4	)%	(52.6	)%	(57.9	)%	11.1	%	(12.7	)%	(4.2	)%	(8.4	)%
CDD	15.1		(4.0	)	20.0		5.4		(2.5	)	8.3		11.0		15.1		(3.1	)	8.3		5.4		3.3
THI	4.3		(17.3	)	29.2		(1.6	)	(11.2	)	13.7		6.5		4.3		3.2		8.6		(1.6	)	11.2

Table of Contents

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


	Three Months Ended Sept. 30									Nine Months Ended Sept. 30								Three Months Ended Sept. 30									Nine Months Ended Sept. 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	$	0.010		$	(0.024	)	$	0.034		$	(0.004	)	$	0.010	$	(0.014	)	$	0.016		^(a)	$	0.010		$	0.006	$	0.011		^(a)	$	(0.004	)	$	0.015
Firm natural gas	(0.002		)	—			(0.002		)	(0.007		)	0.018		(0.025		)	(0.001		)		(0.002		)	0.001		(0.014		)		(0.007		)	(0.007		)
Total	$	0.008		$	(0.024	)	$	0.032		$	(0.011	)	$	0.028	$	(0.039	)	$	0.015			$	0.008		$	0.007	$	(0.003	)		$	(0.011	)	$	0.008

~~Table of Contents~~


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

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


	Three Months Ended Sept. 30										Three Months Ended Sept. 30
	Xcel Energy		PSCo		NSP-Minnesota		NSP-Wisconsin		SPS		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential ^(a)	4.3	%	4.2	%	3.3	%	6.2	%	6.6	%	5.6	%	4.7	%	1.5	%	2.8	%	4.4	%
Electric commercial and industrial	1.1		1.3		0.8		1.9		1.0		0.1		0.8		3.6		—		1.2
Total retail electric sales	1.9		2.2		1.4		3.0		1.4		2.0		2.0		3.2		0.7		2.2
Firm natural gas sales	(5.7	)	(7.9	)	(1.4	)	(3.1	)	N/A		3.5		(5.0	)	N/A		(12.8	)	(0.2	)


	Three Months Ended Sept. 30										Three Months Ended Sept. 30
	Xcel Energy		PSCo		NSP-Minnesota		NSP-Wisconsin		SPS		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized
Electric residential ^(a)	0.6	%	1.5	%	(0.2	)%	(0.6	)%	1.3	%	4.8	%	2.0	%	1.0	%	1.0	%	2.8	%
Electric commercial and industrial	—		(0.7	)	0.2		0.2		0.4		0.5		0.2		3.4		(0.2	)	1.0
Total retail electric sales	0.1		—		—		(0.1	)	0.5		2.1		0.8		3.1		—		1.6
Firm natural gas sales	(0.3	)	(1.3	)	1.6		0.8		N/A		(1.6	)	(4.9	)	N/A		(12.9	)	(3.2	)


	Nine Months Ended Sept. 30										Nine Months Ended Sept. 30
	Xcel Energy		PSCo		NSP-Minnesota		NSP-Wisconsin		SPS		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential ^(a)	(1.4	)%	0.5	%	(2.9	)%	(4.6	)%	(0.3	)%	4.2	%	1.7	%	(1.7	)%	(0.5	)%	1.9	%
Electric commercial and industrial	—		—		(0.3	)	1.3		—		(0.7	)	(0.3	)	1.6		(0.3	)	—
Total retail electric sales	(0.5	)	0.2		(1.1	)	(0.4	)	(0.2	)	0.9		0.3		1.0		(0.5	)	0.6
Firm natural gas sales	(11.2	)	(9.0	)	(14.7	)	(12.5	)	N/A		3.2		(9.0	)	N/A		(12.5	)	(1.8	)


	Nine Months Ended Sept. 30										Nine Months Ended Sept. 30
	Xcel Energy		PSCo		NSP-Minnesota		NSP-Wisconsin		SPS		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized
Electric residential ^(a)	(0.6	)%	(0.1	)%	(1.2	)%	(2.5	)%	1.0	%	3.4	%	0.6	%	(1.2	)%	(0.3	)%	1.3	%
Electric commercial and industrial	—		(0.7	)	0.1		1.5		0.3		(0.7	)	(0.7	)	1.2		(0.4	)	(0.3	)
Total retail electric sales	(0.2	)	(0.5	)	(0.3	)	0.3		0.3		0.7		(0.3	)	0.8		(0.5	)	0.2
Firm natural gas sales	(1.8	)	(2.3	)	(1.1	)	0.1		N/A		0.9		(0.6	)	N/A		(4.7	)	—

Table of Contents



	Nine Months Ended Sept. 30 (Excluding Leap Day) ^(b)
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized - adjusted for leap day
Electric residential ^(a)	3.0	%	0.2	%	(1.6	)%	(0.7	)%	0.9	%
Electric commercial and industrial	(1.1	)	(1.1	)	0.8		(0.7	)	(0.6	)
Total retail electric sales	0.3		(0.7	)	0.4		(0.8	)	(0.2	)
Firm natural gas sales	0.1		(1.4	)	N/A		(5.4	)	(0.7	)


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


^(b)	The estimated impact of the 2016 leap day is excluded to present a more comparable year-over-year presentation. The estimated impact of the additional day of sales in 2016 was approximately 30-40 basis points for retail electric and 70-80 basis points for firm natural gas for the nine months ended Sept. 30, 2016.

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

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

NSP-Minnesota’s residential sales growth reflects customer additions, partially offset by lower use per customer. C&I sales declined primarily as a result of lower use by small and large customers in the manufacturing industry.

SPS’ residential sales decline was primarily the result of lower use per customer. The increase in C&I sales was driven by ~~continued expansion from~~ oil and natural gas ~~exploration and~~ production in the Southeastern New Mexico, Permian Basin ~~area. This~~area as well as greater use by agricultural customers.

NSP-Wisconsin’s residential sales decrease was primarily attributable to lower use per customer, partially offset by customer additions. The C&I decline was largely due to reduced sales to small customers in the sand mining industry. The overall decrease was partially offset by ~~the impact of wet weather which resulted~~an increase in ~~less irrigation by agricultural customers. Residential growth reflects an increased~~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 reduced sales to certain large manufacturing customers and/or those that support the fracking industry. 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 the remaining large and small customers in various industries. The residential decrease was due to less use per customer, partially offset by an increase in 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 Sept. 30						Nine Months Ended Sept. 30						Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Millions of Dollars)	2015			2014			2015			2014			2016			2015			2016			2015
Electric revenues	$	2,667		$	2,616		$	7,106		$	7,216		$	2,800		$	2,667		$	7,209		$	7,106
Electric fuel and purchased power	(1,015		)	(1,080		)	(2,870		)	(3,188		)	(1,037		)	(1,015		)	(2,755		)	(2,870		)
Electric margin	$	1,652		$	1,536		$	4,236		$	4,028		$	1,763		$	1,652		$	4,454		$	4,236

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 Sept. 30
2015 vs. 2014 Nine Months
Ended Sept. 30
2015 vs. 2014
Fuel and purchased power cost recovery $ (90 ) $ (345 )
Conservation and DSM program revenues (offset by expenses) (17 ) (46 )
Estimated impact of weather 26
(11 )
Non-fuel riders ^{(a) (b)}
20
87
Retail rate increases ^(b)
31
80
PSCo earnings test refund 26
61
Transmission revenue 36
58
Trading 10
3
Other, net 9
3
Total increase (decrease) in electric revenues $ 51
$ (110 )

~~Electric Margin~~

(Millions of Dollars) Three Months
Ended Sept. 30
2015 vs. 2014 Nine Months
Ended Sept. 30
2015 vs. 2014
Non-fuel riders ^{(a) (b)}
$ 20
$ 87
Retail rate increases ^(b)
31
80
PSCo earnings test refund 26
61
Transmission revenue, net of costs 22
28
Conservation and DSM program revenues (offset by expenses) (17 ) (46 )
Estimated impact of weather 26
(11 )
Other, net 8
9
Total increase in electric margin $ 116
$ 208



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


^(a)	~~Primarily~~Increase is primarily related to ~~the new CACJA rider~~interim rates in ~~Colorado ($23 million~~Minnesota (subject to and ~~$74 million, respectively).~~net of estimated provision for refund) and final rates in Wisconsin.

Electric Margin



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

^(b)(a)

Increase is primarily due to ~~rate proceedings~~interim rates in Minnesota ~~South Dakota, North Dakota, Texas, New Mexico~~(subject to and ~~Wisconsin. These increases were partially offset by a decline~~net of estimated provision for refund) and final rates in ~~Colorado retail base rates, which was more than offset by increased CACJA rider revenue as approved by the CPUC in the first quarter of 2015.~~ 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 Sept. 30						Nine Months Ended Sept. 30						Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Millions of Dollars)	2015			2014			2015			2014			2016			2015			2016			2015
Natural gas revenues	$	216		$	237		$	1,216		$	1,485		$	222		$	216		$	1,047		$	1,216
Cost of natural gas sold and transported	(66		)	(99		)	(665		)	(934		)	(68		)	(66		)	(470		)	(665		)
Natural gas margin	$	150		$	138		$	551		$	551		$	154		$	150		$	577		$	551

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 Sept. 30
2015 vs. 2014 Nine Months
Ended Sept. 30
2015 vs. 2014
Purchased natural gas adjustment clause recovery $ (28 ) $ (262 )
Estimated impact of weather (1 ) (20 )
Conservation and DSM program revenues (offset by expenses) —
(11 )
Non-fuel riders, partially offset by expenses 7
25
Other, net 1
(1 )
Total decrease in natural gas revenues $ (21 ) $ (269 )



(Millions of Dollars)	Three Months Ended Sept. 30 2016 vs. 2015			Nine Months Ended Sept. 30 2016 vs. 2015
Purchased natural gas adjustment clause recovery	$	(3	)	$	(200	)
Retail rate increases^(a)	8			32
Other, net	1			(1		)
Total increase (decrease) in natural gas revenues	$	6		$	(169	)


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

Natural Gas Margin


(Millions of Dollars)	Three Months Ended Sept. 30 2015 vs. 2014			Nine Months Ended Sept. 30 2015 vs. 2014			Three Months Ended Sept. 30 2016 vs. 2015			Nine Months Ended Sept. 30 2016 vs. 2015
Non-fuel riders, partially offset by expenses	$	7		$	25
Gas transport - Cherokee pipeline	2			4
Retail rate increases^(a)							$	8		$	32
Estimated impact of weather	(1		)	(20		)	—			(5		)
Conservation and DSM program revenues (offset by expenses)	—			(11		)
Non-fuel riders							(3		)	(5		)
Other, net	4			2			(1		)	4
Total increase in natural gas margin	$	12		$	—		$	4		$	26


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

Non-Fuel Operating Expenses and Other Items

O&M Expenses— O&M expenses ~~decreased $2.4~~increased $24.0 million, or ~~0.4~~4.2 percent, for the third quarter of ~~2015~~2016 and ~~increased $32.0~~$18.3 million, or ~~1.9~~1.0 percent, for the nine months ended Sept. 30, 2016 compared with the same periods in 2015. The year-to-date increase ~~in O&M is primarily~~was mainly due to additional maintenance activities and storm related costs, which were partially offset by a reduction in the timing and scope of ~~planned maintenance~~plant outages and ~~overhauls at a number of our generation facilities as well as an increase in contractor costs.~~discovery work.

(Millions of Dollars) Three Months
Ended Sept. 30
2015 vs. 2014 Nine Months
Ended Sept. 30
2015 vs. 2014
Plant generation costs $ (8 ) $ 13
Labor and contract labor 5
11
Electric and natural gas distribution expenses 7
7
Nuclear plant operations (11 ) (7 )
Other, net 5
8
Total (decrease) increase in O&M expenses $ (2 ) $ 32

~~For the third quarter of 2015, O&M expenses decreased due to the following:~~

~~Plant generation costs were related to the timing of overhauls and discovery work; and~~

~~Nuclear expense decreases were primarily due to reduced costs driven by operational initiatives and efficiencies.~~

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Conservation and ~~DSM~~Demand Side Management (DSM) Program Expenses — Conservation and DSM program expenses ~~decreased $17.9~~increased $6.6 million, or 11.5 percent, for the third quarter of ~~2015~~2016 and ~~$58.3~~$12.0 million, or 7.3 percent, for the nine months ended Sept. 30, 2016 compared with the same periods in 2015. ~~The decreases~~Increases were primarily attributable to ~~lower electric~~more customer participation in DSM programs which has led to additional customer rebates and ~~gas recovery rates at NSP-Minnesota and PSCo. Lower~~increased program implementation costs. Higher conservation and DSM program expenses are generally offset by ~~lower revenues.~~higher revenues due to recovery mechanisms.

Depreciation and Amortization — Depreciation and amortization increased ~~$24.7~~$48.4 million, or ~~9.7~~17.3 percent, for the third quarter of ~~2015~~2016 and ~~$71.2~~$143.2 million, or ~~9.4~~17.3 percent, ~~year-to-date.~~for the nine months ended Sept. 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~~Border Wind Farms, reduction of the excess depreciation reserve in Minnesota ~~partially offset by Minnesota’s~~and the full amortization of the DOE ~~settlement.~~settlement in 2015.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) ~~increased $5.1~~decreased $5.9 million, or ~~4.3~~4.8 percent, for the third quarter of ~~2015~~2016 and ~~$30.5~~increased $11.5 million, or ~~8.5~~3.0 percent, for the nine months ended Sept. 30, 2016 compared with the same periods in 2015. ~~Increases were~~The year-to-date increase was primarily due to higher property taxes ~~primarily~~ in ~~Colorado and Minnesota.~~

~~AFUDC, Equity and Debt~~ ~~— AFUDC decreased $10.8 million for~~Minnesota, excluding the ~~third quarter of 2015 and $38.4 million year-to-date. Decreases were primarily due to the implementation~~impact of the ~~CACJA rider on Jan. 1, 2015, facilitating earlier and alternative recovery of construction costs.~~proposed settlement agreement in the Minnesota 2016 multi-year electric rate case.

Interest Charges — Interest charges increased ~~$9.3~~$13.3 million, or ~~6.5~~8.7 percent, for the third quarter of ~~2015~~2016 and ~~$20.0~~$43.6 million, or ~~4.7~~9.9 percent, for the nine months ended Sept. 30, 2016 compared with the same periods in 2015. Increases were ~~primarily due~~related to higher long-term debt levels to fund capital investments, partially offset by refinancings at lower interest rates.

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Income Taxes —Income tax expense ~~increased $43.1~~decreased $0.6 million for the third quarter of ~~2015~~2016 compared with the same period in ~~2014.~~2015. The ~~increase~~decrease was primarily due to increased wind production tax and research and experimentation credits in 2016, partially offset by higher pretax earnings ~~and decreased permanent plant-related adjustments~~ in ~~2015.~~2016. The ETR was ~~35.9~~34.2 percent for the third quarter of ~~2015~~2016 compared with ~~34.7~~35.9 percent for the same period in ~~2014.~~2015. The ~~higher~~lower ETR ~~for 2015 was~~in 2016 is primarily due to the ~~plant-related~~ adjustments referenced above.

Income tax expense ~~decreased $3.5~~increased $39.0 million for the first nine months of ~~2015~~2016 compared with the same period in ~~2014.~~2015. The ~~decrease~~increase in income tax expense was primarily due to ~~lower~~higher pretax earnings, partially offset by ~~decreased permanent plant-related adjustments~~increased wind production tax and ~~the successful resolution of a 2010-2011 IRS audit issue in 2014.~~research and experimentation credits. The ETR was ~~35.8~~34.5 percent for the first nine months of ~~2015,~~2016 compared ~~to 34.6~~with 35.8 percent for the ~~first nine months of 2014~~same period in 2015. The lower ETR in 2016 is primarily due to ~~these adjustments.~~the adjustments referenced above.

Public Utility Regulation ~~and Legislation~~

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 1 of Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2014,~~2015 and Public Utility Regulation included in Item 2 of Xcel Energy Inc.’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, ~~2015~~2016 and June 30, ~~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~~ — In September 2015, NSP-Minnesota began construction of the Courtenay wind farm, a 200 MW NSP-Minnesota owned project in North Dakota. In May 2015, NSP-Minnesota filed for expedited regulatory approval in Minnesota and North Dakota. In July and August 2015, the MPUC and NDPSC, respectively, approved the Courtenay wind farm with recovery up to $300 million of capital costs. The project costs were requested to be recovered through the Minnesota renewable energy standard rider and the North Dakota renewable energy rider.

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

~~On Oct. 2, 2015,~~Subsequently, NSP-Minnesota ~~filed~~proposed revisions to the ~~Plan. The revised proposal~~Plan, which addressed stakeholder recommendations as well as the ~~final~~ Clean Power Plan ~~(CPP) recently~~ issued by the EPA. The revised ~~Plan is~~plan was based on four primary elements: (1) accelerate the transition from coal energy to renewables, (2) preserve regional system reliability, (3) pursue energy efficiency gains and grid modernization, and (4) ensure customer benefits. The ~~provisions included~~revised plan includes substantial opportunities for NSP-Minnesota ownership of renewable generation, and would result in ~~the Plan would allow for~~63 percent of NSP System energy being carbon-free by 2030 and a 60 percent reduction in carbon emissions from 2005 levels by ~~2030 and will result in 63 percent of NSP System energy being carbon-free by~~ 2030.

Specific terms of the proposal include:

The addition of ~~800~~1,800 MW of wind and ~~400~~1,400 MW of ~~utility scale solar to the pre-2020 time-frame;~~

~~The addition of 1000 MW wind and 1000 MW utility scale~~ solar between ~~2020-2030;~~2016-2030, including approximately 650 MW of solar from NSP-Minnesota’s community solar gardens program by 2020;

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

~~The addition of a 230 MW (approximate capacity, actual size to be determined) natural gas combustion turbine in North Dakota by 2025;~~

~~Replacement~~Partial replacement of Sherco coal generation with a ~~780~~786 MW ~~(approximate capacity, actual size to be determined)~~ natural gas combined cycle unit at the Sherco site ~~no later than 2026; and~~to coincide with the Unit 1 retirement;

The addition of a 230 MW natural gas combustion turbine in North Dakota by the end of 2025;

Operation of the Monticello and PI nuclear plants through their current license periods in the early ~~2030’s.~~2030’s - and a commitment to provide additional information regarding forecasted cost increases at PI through end of licensed life if the MPUC wishes to further explore alternatives to operating PI through its current license periods.

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

The acquisition of at least 1,000 MW of wind by 2019, with additional acquisitions dependent on considerations such as price, bidder qualifications, rate impact, transmission availability and location;

The acquisition of 650 MW of solar before 2021 through the community solar gardens program or other acquisitions - and pursuit of additional, cost-effective solar resources if it is in the best interests of its customers;

Determination of the proper mix of purchased power and Company-owned renewable resources shall be made during the resource acquisition process;

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

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Authorization for NSP-Minnesota ~~believes this will provide substantial opportunities~~to file a petition for a certificate of need to select the ~~ownership~~resource that best meets the system resource and local reliability needs associated with the retirement of ~~replacement~~Sherco Unit 1 in 2026;

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

Submission of NSP-Minnesota’s next Resource Plan by February 2019.

The MPUC’s order on NSP-Minnesota’s Resource Plan is ~~currently being reviewed by the MPUC.~~expected in late 2016.

~~CapX2020~~Request for Proposal (RFP) — In September 2016, NSP-Minnesota issued a RFP for 1,500 MW of wind generation to be in service by 2020. The ~~estimated cost of~~RFP requests both PPAs and Build-Own-Transfer proposals. NSP-Minnesota intends to compare self-build options to the ~~five major CapX2020 transmission projects listed below is $2 billion. NSP-Minnesota and NSP-Wisconsin~~RFP bids to ensure that all resource additions are responsible for approximately $1.1 billion of the total investment. As of Sept. 30, 2015, Xcel Energy has invested $975.5 million of its $1.1 billion share of the five CapX2020 transmission projects. The projects are as follows:cost-competitive.

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

An overview of the anticipated RFP schedule is as follows:

Project proposal selection and negotiation will occur from November 2016 to ~~La Crosse, Wis. 161/345 Kilovolt (KV) transmission line~~ ~~— The project~~March 2017;

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

MPUC approval is expected to go into service in the fall of 2016, although segments are being placed in service as they are completed. The first 345 KV segment was energized in September 2015 and stretches from the North Rochester Substation in Minn. to the Briggs Road Substation in Wis.

by July 2017.

~~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 project was placed in service in September 2012.~~

~~Big Stone South to Brookings County, S.D. 345 KV transmission line~~ ~~— Construction on the line began in September 2015, with completion anticipated 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 additional large-scale solar to its system by the end of 2016.~~

NSP-Minnesota also offers ~~small~~customer solar programs: a solar production incentive program for rooftop solar, called Solar*~~Rewards,~~Rewards®, and a community solar garden program that provides bill credits to participating subscribers, called Solar*~~Rewards Community.~~Rewards® Community®. Additionally, the ~~Department of Commerce~~DOC offers the ~~Made~~“Made in ~~Minnesota incentive~~Minnesota” program, providing incentives for the installation of small solar ~~using products made~~systems that were manufactured in-state, which generates renewable energy credits for utilities including NSP-Minnesota.

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 August 2015, the MPUC issued an order regarding the Solar*Rewards Community program, limiting the size of solar installations eligible to participate in the ~~program, more closely aligning~~program. The order was appealed to the ~~program with its original intent.~~Minnesota Court of Appeals, which affirmed the MPUC’s decision. The ~~MPUC~~ decision ~~limits projects~~was subsequently appealed to ~~five MW or less through Sept. 25, 2015. Subsequently, projects must be one MW or less. In October 2015,~~ the ~~MPUC~~Minnesota Supreme Court, which denied ~~requests for reconsideration of~~ the ~~project size limitation.~~appeal in September 2016, terminating the case.

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~~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 MYPs and more certainty regarding recovery of costs and the impact to customers. This bill provides:

~~Increased flexibility for utilities to submit a 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, such as in a resource plan; 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 ~~Regulatory Performance~~— ~~The NRC has a Reactor Oversight Process that classifies U.S. nuclear reactors into various categories (referred to as Columns, from~~Power Operations and Waste Disposal included in Item 1 ~~to 5). Such issues are evaluated as either green, white, yellow, or red based~~of Xcel Energy Inc.’s Annual Report on ~~their safety significance, with green representing~~Form 10-K for the ~~least safety concern and red representing the most concern.~~

Atyear ended Dec. 31, ~~2014, Monticello was~~2015 and Nuclear Power Operations included in ~~Column 3 (degraded cornerstone) with~~Item 2 of Xcel Energy Inc.’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30, 2016, appropriately represent, in all ~~green performance indicators, a yellow finding related to flood control~~material respects, the current status of nuclear power operations, and a potentially greater than green finding related to plant security. In March 2015, Monticello was upgraded from Column 3 to Column 2 (regulatory response) based on the results of an NRC inspection in late 2014 to close out the flood control finding. The NRC conducted an inspection on the security finding in July 2015. Based on the results of the NRC inspection, Monticello was upgraded to Column 1 on Oct. 1, 2015.

~~As of Oct. 1, 2015, Monticello and PI Units 1 and 2 were in Column 1 (licensee response) with all green performance indicators and no greater than green findings or violations. Plants in Column 1~~ are ~~subject to only a pre-defined set of basic NRC inspections.~~incorporated herein by reference.

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 co-owners, Dairyland Power Cooperative, WPPI Energy and Southern Minnesota Municipal Power Agency-Wisconsin.

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 circuit 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 is expected to 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.

~~2015~~2016 Electric Fuel Cost Recovery — NSP-Wisconsin’s electric fuel costs for the nine months ended Sept. 30, ~~2015~~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 load as a result of mild weather, lower natural gas prices and lower purchased power prices in the MISO market.~~rules. 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 ~~$5.9~~$6.6 million through Sept. 30, ~~2015.~~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 ~~2016,~~2017 NSP-Wisconsin will file a reconciliation of ~~2015~~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-2016.~~mid-2017.

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PSCo

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

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

Answer testimony — Dec. 9, 2016;

Rebuttal testimony — Jan. 17, 2017;

Hearings — Feb. 1-8, 2017; and

Statements of position — Feb. 17, 2017.

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

Rush Creek Wind Ownership Proposal — In May 2016, PSCo ~~had previously~~filed an application to build, own and operate a 600 MW wind generation facility at Rush Creek for a cost of approximately $1 billion, including transmission investment.

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

Key terms of the settlement are listed below:

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

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

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

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

A capital cost sharing mechanism for every $10 million below the cost-cap, with 82.5 percent retained by customers and 17.5 percent retained by PSCo on a net present value basis over the life of the project;

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

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

PSCo Global Settlement Agreement — In August 2016, PSCo and various intervenors, including small and large customers, state representatives, environmental advocates and solar and energy groups, entered into a global settlement agreement regarding three pending filings with the CPUC, including the Phase II electric rate case (which is related to the rate design portion of the 2015 Electric Rate Case), the Renewable*Connect proposal (formally known as Solar*Connect) and the 2017 Renewable Energy Plan. Key terms of the agreement include that participating customers in the proposed Renewable*Connect program would pay ordinary tariff electric rates in addition to ~~track~~a voluntary tariff solar charge, and ~~quantify~~receive bill credits related to avoided cost savings for a new 50 MW solar resource. It was also agreed that PSCo’s 2017 Renewable Energy Plan would include 2017 to 2019 acquisition of a total of 225 MW of renewable energy from sources including rooftop solar, solar gardens and recycled energy.

A CPUC decision is expected by December 2016, which would allow PSCo to issue a RFP for the new Renewable*Connect solar facility and implement the 2017 Renewable Energy Plan and the rate design changes of the Phase II electric rate case beginning January 2017.

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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. PSCo proposed with the CPUC that margins on these sales be shared among PSCo and its customers, of which 10 percent would be retained by PSCo. A decision by the CPUC is anticipated in the fourth quarter of 2016. The JDA parties estimate the combined net benefits of the agreement would be approximately $4.5 million, annually. The agreement results in a reduction in total energy costs for the parties, of which approximately $1.4 million would be allocated to PSCo’s customers. As part of the agreement, PSCo will earn a management fee to administer the JDA. We expect operations under the JDA to begin in the fourth quarter of 2016.

Advanced Grid Intelligence and Security —In August 2016, PSCo filed a request with the CPUC to approve a certificate of public convenience and necessity 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 ~~costs that~~to operate at a lower voltage (integrated volt-var optimization) and installing necessary communications infrastructure to implement this hardware. These major projects are ~~not avoided~~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. PSCo anticipates a CPUC decision by distributed solar generation, which PSCo has defined as a “net metering incentive,” for purposes of equitably recovering costs between customers. The CPUC assigned the net metering issue to its own docket and conducted a series of panel discussions to gain a better understanding of net metering issues. In the third quarter of 2017. If approval is received, the project is expected to be completed by 2021.

Decoupling Filing — In July 2016, PSCo filed a request with the CPUC ~~closed~~to approve a partial decoupling mechanism for a five year period, effective on Jan. 1, 2017. The proposed decoupling adjustment would allow PSCo to adjust annual revenues based on changes in weather normalized average use per customer for the ~~net metering docket, concluding~~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 ~~they would~~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 ~~make any changes~~request that revenue be adjusted as a result of weather related sales fluctuations.

In August 2016, a majority of the parties to the ~~net metering policies. The decision does not preclude the~~ PSCo ~~from filing changes~~Global Settlement Agreement agreed to limit any future opposition to PSCo’s decoupling proposal to the ~~PSCo’s net metering practices~~specifics of design and implementation.

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

Direct testimony — Dec. 14, 2016;

Answer testimony — Jan. 16, 2017;

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

Hearings — Feb. 21-24, 2017.

A decision is anticipated in the first quarter of 2017.

Boulder, Colo. Municipalization — ~~PSCo’s franchise agreement with the City of Boulder (Boulder) expired 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 to certain restrictions, including the level of initial rates and debt service coverage. In May 2014, the City of Boulder (Boulder) City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility as premature because costs and system separation plans were not final, but the case was dismissed. PSCo appealed this decision and in September 2016, the Colorado Court of Appeals preserved PSCo’s ability to challenge the utility while vacating the lower court’s decision.

In 2013, the CPUC ruled that Boulder may not be the retail service provider to any PSCo customers located outside Boulder city limits unless Boulder can establish that PSCo is unwilling or unable to serve those customers. The CPUC also ruled that it has jurisdiction ~~under Colorado law~~over the transfer of any facilities to ~~determine the utility~~Boulder that ~~will~~currently serve any customers located outside ~~Boulder’s~~Boulder city limits and will determine ~~system~~ separation ~~matters as well as what facilities need to be constructed to ensure reliable service.~~matters. The CPUC has declared that ~~it should make its determinations~~Boulder must receive CPUC transfer approval 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. The Boulder District Court also dismissed a condemnation action that Boulder had filed. The CPUC must complete the separation plan proceeding before Boulder may refile a condemnation proceeding.

~~Boulder sent PSCo an offer~~

Table 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.Contents

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, PSCo filed a petition with the FERC requesting an order requiring 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 for the business and its associated property taken by Boulder, as well as for all damages resulting to PSCo and its system. PSCo would also seek appropriate compensation for stranded costs with the FERC.

In April 2015, Boulder issued a request for proposal for a partial requirements wholesale electric power supply agreement. Boulder indicated that the request for proposal was designed to elicit a wholesale power supply arrangement for a five-year term commencing 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. In May 2015, PSCo sent Boulder a letter indicating its willingness to discuss a power supply arrangement with Boulder, but no formal offer was made.

In July 2015, Boulder filed an application with the CPUC requesting approval of ~~Boulder’s~~its proposed separation ~~plan, seeking to take certain distribution assets of PSCo outside of the city limits but allowing PSCo to bill the customers for service.~~plan. In August 2015, PSCo ~~brought~~filed a ~~Motion~~motion to ~~Dismiss~~dismiss Boulder’s separation proposal, arguing Boulder’s request was not permissible under Colorado law. ~~The matter is now pending before the CPUC.~~

~~Cabin Creek Hydro Upgrade~~ — PSCo filed a CPCN with the CPUC 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. In ~~August~~December 2015, the CPUC granted the motion to dismiss the application ~~for~~in part, holding that Boulder had no right to acquire PSCo facilities used exclusively to serve customers located outside Boulder city limits. Other portions of Boulder’s application were not dismissed, but were stayed until Boulder supplemented its application. Boulder filed its amended application in September 2016, and in the ~~upgrade.~~application, Boulder estimates it would incur approximately $53 million of costs to separate from the PSCo system.

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SPS

~~Chaves~~TUCO Substation to Yoakum County ~~N.M. Solar Contracts~~Substation to Hobbs Plant Substation 345 Kilovolt (KV) Transmission Line— — In ~~March~~June 2015, SPS ~~entered into two purchased energy contracts~~filed a certificate of convenience and necessity (CCN) with ~~NextEra Resources~~the PUCT for the ~~purchase~~33-mile Yoakum County to Texas/New Mexico State line portion of ~~solar generated electricity from two 70 MW projects~~this 345 KV line project. The PUCT approved this CCN in March 2016. A CCN for the 111-mile TUCO to Yoakum County substation segment was filed in June 2016. Assuming approval of this CCN, this segment is scheduled to be ~~constructed~~ in ~~Chaves County, N.M.~~service in 2019. A 20-mile CCN for the Texas/New Mexico state line to Hobbs Plant segment is planned to be filed in the fourth quarter of 2016 or early 2017. The ~~two 25-year contracts were subject to regulatory approval, which the NMPRC granted in October 2015. The purchased energy will be recovered from customers through SPS’ fuel and purchased energy~~estimated project cost ~~recovery mechanisms.~~for all three segments is approximately $242 million.

Wholesale Customer Participation in Electric Reliability Council of Texas (ERCOT) — In March 2016, the PUCT Staff requested comments on Lubbock Power & Light’s (LP&L’s) proposal to transition a portion of its load (approximately 430 MW on a peak basis) to the ERCOT in June 2019. LP&L’s proposal would result in an approximate seven percent reduction of load in SPS, or a loss of approximately $18 million in wholesale transmission revenue based on 2015 revenue requirements. The remaining portion of LP&L’s load (approximately 170 MW) would continue to be served by SPS. Should LP&L join ERCOT, costs to SPS’ remaining customers would increase as SPS’ transmission costs would be spread across a smaller base of customers.

The PUCT has indicated there will be a two-step process regarding LP&L’s possible transfer to ERCOT. The first step will be a proceeding to determine whether the proposed transfer is in the public interest and to consider certain protections for non-LP&L customers who would be affected by LP&L’s transfer. If the PUCT determines the transfer is in the public interest, the second step will be for LP&L to file a CCN application for transmission facilities to connect with ERCOT. As part of the first process, the PUCT asked SPP and ERCOT to perform reliability and economic studies to better understand the implications of LP&L’s proposal. SPS intends to participate in the PUCT’s processes to protect its customers’ interests.

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

Summary of Recent Federal Regulatory Developments

The Pipeline and Hazardous Materials Safety Administration

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

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

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

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FERC

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of Xcel Energy Inc.’s utility subsidiaries and transmission-only subsidiaries, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of Xcel Energy Inc.’s utility subsidiaries’ activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2014.~~2015 and Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30, 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. ~~In March, 2015, FERC upheld the new ROE methodology and denied rehearing.~~ The issue of how to apply the new FERC ROE methodology is being contested in various complaint proceedings. There are two ROE complaints against the MISO TOs, which include NSP-Minnesota and NSP-Wisconsin. In September 2016, the FERC issued an order in the first MISO ROE complaint which upheld the initial decision made by the ALJ in December 2015. The second complaint is pending FERC action after issuance of an initial decision by the ALJ in June 2016. FERC is not expected to issue ~~orders~~an order in ~~any of~~ the second litigated MISO ROE complaint ~~proceedings~~proceeding until ~~2016.~~2017. See Note 5 to the consolidated financial statements for discussion of the ~~SPS Wholesale Rate Complaints and~~ MISO ROE Complaints.

Formula Rate Treatment of Accumulated Deferred Income Taxes (ADIT) — In 2015, NSP-Minnesota, NSP-Wisconsin, SPS and PSCo filed changes to their transmission formula rates and PSCo filed changes to its production formula rate, 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.

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

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

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

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

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Derivatives, Risk Management and Market Risk

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

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

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

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

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

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At Sept. 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	$	2,679	$	7,119	$	1,261	$	356	$	11,415	1	$	2,719	$	6,582	$	1,500	$	303	$	11,104
NSP-Minnesota	2	2,573		—		—		—		2,573
PSCo												1	461		2		—		—		463
		$	5,252	$	7,119	$	1,261	$	356	$	13,988		$	3,180	$	6,584	$	1,500	$	303	$	11,567


	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	$	254	$	—	$	—	$	—	$	254	2	$	(16	)	$	—	$	—	$	—	$	(16	)

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

2 — Prices based on models and other valuation methods.

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


	Nine Months Ended Sept. 30						Nine Months Ended Sept. 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	(4,400		)	(9,225		)	(2,628		)	(4,400		)
Commodity trading contract additions and changes during period	(3,169		)	2,676			3,139			(3,169		)
Fair value of commodity trading net contract assets outstanding at Sept. 30	$	14,242		$	23,965		$	11,551		$	14,242

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At Sept. 30, 2016, a 10 percent increase in market prices for commodity trading contracts would decrease pretax income from continuing operations by approximately $0.3 million, whereas a 10 percent decrease would increase pretax income from continuing operations by approximately $0.3 million. At Sept. 30, 2015, a 10 percent increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $0.5 million, whereas a 10 percent decrease would decrease pretax income from continuing operations by approximately $0.5 million. At Sept. 30, 2014, a 10 percent increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $1.4 million, whereas a 10 percent decrease would decrease pretax income from continuing operations by approximately $1.4 million.

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

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


(Millions of Dollars)	Three Months Ended Sept. 30		VaR Limit		Average		High		Low		Three Months Ended Sept. 30		VaR Limit		Average		High		Low
2016											$	0.10	$	3.00	$	0.18	$	0.38	$	0.05
2015	$	0.17	$	3.00	$	0.23	$	0.63	$	0.10	0.17		3.00		0.23		0.63		0.10
2014	0.60		3.00		0.50		4.06		0.13

Nuclear Fuel Supply — NSP-Minnesota is scheduled to take delivery of approximately 87 percent of its 2016 and approximately 13 percent of its ~~2015 and approximately 46 percent of its 2016~~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 35 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.

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

At Sept. 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 ~~$0.8~~$4.2 million and ~~$7.1~~$0.8 million, respectively. See Note 8 to the consolidated financial statements for a discussion of Xcel Energy Inc. and its subsidiaries’ interest rate derivatives.

NSP-Minnesota also maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. At Sept. 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 Sept. 30, 2016, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $11.7 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $15.9 million. At Sept. 30, 2015, a 10 percent increase in commodity prices would have resulted in a decrease in credit exposure of $4.8 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $11.7 million. ~~At Sept. 30, 2014, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure~~

Table of ~~$35.2 million, while a decrease in prices of 10 percent would have resulted in a decrease in credit exposure of $14.1 million.~~Contents

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 Sept. 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 Sept. 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 ~~2.0~~1.3 percent and ~~20.1~~8.0 percent of total assets and liabilities, respectively, measured at fair value at Sept. 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 ~~$38.8~~$27.8 million and ~~$7.8~~$3.2 million of estimated fair values, respectively, for FTRs held at Sept. 30, ~~2015.~~2016.

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

~~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 $218 million in the nuclear decommissioning fund at Sept. 30, 2015 (approximately 11.0 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


	Nine Months Ended Sept. 30				Nine Months Ended Sept. 30
(Millions of Dollars)	2015		2014		2016		2015
Cash provided by operating activities	$	2,490	$	2,004	$	2,413	$	2,490

Net cash provided by operating activities ~~increased $486~~decreased $77 million for the nine months ended Sept. 30, ~~2015~~2016 compared with the nine months ended Sept. 30, ~~2014.~~2015. The ~~increase~~decrease was primarily due to ~~higher electric cost recovery in 2015,~~ timing of customer receipts, refunds and 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 in ~~2014, solar garden deposits received in 2015 and income tax refunds received in 2015 compared to taxes paid in 2014.~~2015).


	Nine Months Ended Sept. 30						Nine Months Ended Sept. 30
(Millions of Dollars)	2015			2014			2016			2015
Cash used in investing activities	$	(2,139	)	$	(2,235	)	$	(2,206	)	$	(2,139	)

Net cash used in investing activities ~~decreased $96~~increased $67 million for the nine months ended Sept. 30, ~~2015~~2016 compared with the nine months ended Sept. 30, ~~2014.~~2015. The ~~decrease~~increase was primarily attributable to ~~higher capital expenditures~~the establishment of rabbi trusts in 2014 related to CACJA initiatives, including the construction of a natural gas fired combined cycle unit at Cherokee generating station and the addition of emissions controls at Pawnee station, as well as natural gas pipeline construction projects2016 and the impact of higher insurance proceeds ~~related to Sherco Unit 3~~ received in 2015.

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	Nine Months Ended Sept. 30					Nine Months Ended Sept. 30
(Millions of Dollars)	2015			2014		2016		2015
Cash (used in) provided by financing activities	$	(26	)	$	261
Cash provided by (used in) financing activities						$	62	$	(26	)

Net cash provided by financing activities was $62 million for the nine months ended Sept. 30, 2016 compared with net cash used in financing activities ~~was~~of $26 million for the nine months ended Sept. 30, 2015, ~~compared with net cash provided by financing activities of $261 million for the nine months ended Sept. 30, 2014,~~ or a change of ~~$287~~$88 million. The difference was primarily due to ~~higher~~lower repayments of short-term debt, ~~and fewer issuances of common stock in 2015,~~ partially offset by higher repayments of long-term debt ~~issuances in 2015.~~and dividend payments.

Capital Requirements

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

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



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



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

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

Financing — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes. Xcel Energy does not anticipate issuing any equity to fund its capital investment program for 2017-2021. The current estimated financing plans of Xcel Energy Inc. and its subsidiaries for the years 2017 through 2021 are shown in the table below.

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

Maturing Debt	$	3,550


*	Net of dividends.


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

Regulation of Derivatives — In July 2010, financial reform legislation was passed that provides for the regulation of derivative transactions amongst other provisions. Provisions within the ~~law~~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.

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~~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 ~~law~~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.~~requirements and transaction restrictions.

~~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) 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 Sept. 30, 2015, SPS had a $10 million letter of credit posted with SPP, which was a reduction from the previous requirement of $36 million.

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

In January ~~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.~~deemed appropriate based on evaluation of various factors including the funded status of the plans, minimum funding requirements, interest rates and expected investment returns.

Capital Sources

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

Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts. At Sept. 30, ~~2015,~~2016, approximately ~~$330.2~~$281.7 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.

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Credit Facilities —As of Oct. ~~26, 2015,~~24, 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	$	—	$	1,000	$	6	$	1,006	$	1,000	$	263	$	737	$	—	$	737
PSCo	700		4		696		1		697		700		22		678		1		679
NSP-Minnesota	500		23		477		156		633		500		11		489		—		489
SPS	400		10		390		1		391		400		5		395		1		396
NSP-Wisconsin	150		15		135		1		136		150		37		113		1		114
Total	$	2,750	$	52	$	2,698	$	165	$	2,863	$	2,750	$	338	$	2,412	$	3	$	2,415


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


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

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

$1 billion for Xcel Energy Inc.;

$700 million for PSCo;

$500 million for NSP-Minnesota;

$400 million for SPS; and

$150 million for NSP-Wisconsin.

Commercial paper outstanding for Xcel Energy was as follows:


(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2015			Twelve Months Ended Dec. 31, 2014			Three Months Ended Sept. 30, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	2,750		$	2,750		$	2,750		$	2,750
Amount outstanding at period end	64			1,020			366			846
Average amount outstanding	272			841			477			601
Maximum amount outstanding	478			1,200			609			1,360
Weighted average interest rate, computed on a daily basis	0.46		%	0.33		%	0.77		%	0.48		%
Weighted average interest rate at period end	0.38			0.56			0.77			0.82

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.

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

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

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

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

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

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

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During ~~2015,~~2016, Xcel Energy Inc. and its utility subsidiaries ~~completed~~issued and anticipate issuing the ~~following bond issuances:~~following:

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

In ~~June, NSP-Wisconsin~~May, NSP-Minnesota issued ~~$100~~$350 million of ~~3.3~~3.6 percent first mortgage bonds due May 15, 2046;

In June, PSCo issued $250 million of 3.55 percent first mortgage bonds due June 15, ~~2024;~~2046;

In August, ~~NSP-Minnesota~~SPS issued $300 million of ~~2.2~~3.4 percent first mortgage bonds due Aug. 15, ~~2020~~2046; and ~~$300~~

Xcel Energy Inc. plans to issue approximately $800 million of ~~4.0 percent first mortgage bonds due Aug. 15, 2045; and~~

~~In September, SPS issued $200 million of 3.3 percent first mortgage bonds due June 15, 2024.~~senior notes in the fourth quarter.

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

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

~~Xcel Energy Inc. plans to issue approximately $600 million of senior unsecured bonds;~~

~~NSP-Minnesota plans to issue approximately $250 million of first mortgage bonds; and~~

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

~~Dividend Reinvestment and Stock Purchase Plan and Stock Compensation Settlements~~ — In October 2015, the Xcel Energy Inc. Board of Directors authorized open market purchases by the plan administrator as the source of shares for the dividend reinvestment program as well as market purchases of up to 3.0 million shares for stock compensation plan settlements.

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Off-Balance-Sheet Arrangements

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

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

Xcel Energy’s revised ~~2015~~2016 ongoing earnings guidance is $2.17 to ~~$2.05 to $2.15~~$2.22 per share, compared with the previous issued guidance of ~~$2.00~~$2.12 to ~~$2.15~~$2.27 per share.^(a) 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 be relatively flat.

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

~~Capital rider revenue is projected to increase by $150 million to $160 million over 2014 levels.~~

~~The change in O&M expenses is projected to be within a range of 0 percent to 2 percent from 2014 levels.~~

Depreciation expense is projected to increase $110 million to $120 million over 2014 levels. The change in the depreciation assumption reflects an adjustment for eliminations and will not have any impact on earnings.

~~Property taxes are projected to increase approximately $50 million to $60 million over 2014 levels.~~

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

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

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

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

~~Xcel Energy’s 2016 ongoing earnings guidance is $2.12 to $2.27 per share. Key assumptions related to 2016 earnings are detailed below:~~

~~Constructive outcomes in all rate case and regulatory proceedings, including the implementation of interim rates in Minnesota consistent with historical precedent.~~

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

~~Weather-normalized retail electric utility sales are projected to increase approximately 0.5 percent to 1.0 percent.~~

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

Capital rider revenue is projected to increase by ~~$70~~$35 million to ~~$80~~$45 million over 2015 levels.

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

Depreciation expense is projected to increase approximately ~~$200~~$185 million to $195 million over 2015 levels. Approximately $20 million of the increased depreciation expense and amortization will be recovered through the renewable development fund rider (not included in the capital rider) in Minnesota.

Property taxes are projected to increase approximately ~~$40~~$20 million to ~~$50~~$25 million over 2015 levels.

Interest expense (net of AFUDC — debt) is projected to increase ~~$40~~$50 million to ~~$50~~$60 million over 2015 levels.

AFUDC — equity is projected to ~~decline~~increase approximately $5$0 million to $10 million from 2015 levels.

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

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

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

Constructive outcomes in all rate case and regulatory proceedings.

Normal weather patterns are experienced for the year.

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

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

Capital rider revenue is projected to increase by $65 million to $75 million over 2016 levels.

O&M expenses are projected to be flat.

Depreciation expense is projected to increase approximately $160 million to $170 million over 2016 levels.

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

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

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

The ETR is projected to be approximately 32 percent to 34 percent.

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


^(a)	Given the unplanned and/or unknown nature of adjustments that may be necessary to reconcile ongoing diluted EPS to GAAP diluted EPS, Xcel Energy is unable to provide a quantitative reconciliation of the guidance for ongoing diluted EPS to corresponding GAAP diluted EPS.

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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;

Deliver annual dividend increases of 5 percent to 7 percent;

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

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

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

~~Table of Contents~~

Item 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Sept. 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.

~~Table of Contents~~

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table provides information about our purchases of equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Exchange Act for the quarter ended Sept. 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
July 1, 2016 — July 31, 2016	—	$	—	—	—
Aug. 1, 2016 — Aug. 31, 2016 ^(a)	47,802	42.22		—	—
Sept. 1, 2016 — Sept. 30, 2016	—	—		—	—
Total	47,802			—	—

^(a)

~~Issuer Purchases~~Xcel Energy Inc. or one 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~~its agents periodically purchases common shares in order to satisfy obligations under the ~~Plans or Programs~~

~~July 1, 2015 — July 31, 2015~~

—

~~Aug. 1, 2015 — Aug. 31, 2015~~

—

~~Sept. 1, 2015 — Sept. 30, 2015~~

—

~~Total~~

—

Stock Equivalent Plan for Non-Employee Directors.

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 Indenture dated as of Aug. 1, ~~2015~~2016 between ~~NSP-Minnesota~~SPS and ~~The~~U.S. Bank ~~of New York Mellon Trust Company, N.A.,~~National Association, as ~~successor~~ Trustee, creating $300,000,000 principal amount of ~~2.20~~3.40 percent First Mortgage Bonds, Series No. 4 due ~~Aug. 15, 2020 and $300,000,000 principal amount of 4.00 percent First Mortgage Bonds, Series due Aug. 15, 2045~~2046. (Exhibit ~~4.01~~4.02 to Form 8-K of ~~NSP-Minnesota~~SPS dated Aug. ~~11, 2015~~12, 2016 (file no. ~~001-31387)~~001-03789)).
10.01+	Third Amendment dated Sept. 30, 2016 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarter ended Sept. 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.

6259

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SIGNATURES

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



		XCEL ENERGY INC.

Oct. ~~30, 2015~~28, 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)

6360



(Millions of Dollars)	MPUC July Decision
2014 and 2015 step 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 2014 and 2015 step increase	$	149.4
Impact of interim rate effective March 3, 2015	(3.6		)
Estimated 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 HTY	(10.5		)	(16.4		)
Operating and maintenance (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			ALJs’ PFD ^(a)
(Millions of Dollars)	AXM			OPUC			Staff			SPS Rebuttal Testimony			ALJs’ PFD ^(a)
SPS’ revised rate request	$	58.9		$	58.9		$	58.9		$	58.9		$	42.1
Investment for capital expenditures — post-test year adjustments	(11.3		)	(23.8		)	(23.8		)	—			(16.7		)
Lower ROE	(10.9		)	(13.5		)	(12.1		)	—			(6.3		)
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		)	(5.3		)
Depreciation expense	(13.3		)	—			—			—			(3.9		)
Property taxes	—			(1.2		)	(4.4		)	(1.8		)	(3.7		)
Revenue adjustments	(2.2		)	(0.2		)	—			—			—
Wholesale load reductions	(13.2		)	—			(11.1		)	—			—
Southwest Power Pool (SPP) transmission expansion plan	—			—			—			(7.3		)	(4.2		)
Other, net	(1.7		)	(0.6		)	(2.2		)	(1.8		)	(0.6		)
Total recommendation	$	(13.6	)	$	1.8		$	(2.6	)	$	46.4		$	1.4
Adjustment to move rate case expenses to a separate docket	—			—			—			(4.3		)	(0.2		)
Recommendation, excluding rate case expenses	$	(13.6	)	$	1.8		$	(2.6	)	$	42.1		$	1.2



(Millions of Dollars)	Request
2015 base period deficiency	$	19.7
Capital expenditures — post-test year adjustments	12.3
Depreciation, higher rates reflecting changes in depreciable lives, interim retirements and net salvage	3.7
Transmission revenue and expense, including charges paid to SPP for construction of regionally shared transmission projects	2.0
ROE, reflecting an increase from 9.96 percent to 10.25 percent	1.6
Rider revenue adjustments - gross receipts tax	1.3
Other, net	4.8
Requested rate increase	$	45.4



(Thousands of Dollars)	July 1, 2015		Purchases		Settlements			Gains Recognized as Regulatory Assets ^(a)		Sept. 30, 2015
Private equity investments	$	133,993	$	3,066	$	—		$	8,636	$	145,695
Real estate	70,834		1,501		(1,719		)	1,360		71,976
Total	$	204,827	$	4,567	$	(1,719	)	$	9,996	$	217,671

(Thousands of Dollars)	July 1, 2014		Purchases		Settlements			Gains Recognized as Regulatory Asset ^(a)		Sept. 30, 2014
Private equity investments	$	81,123	$	11,125	$	—		$	4,756	$	97,004
Real estate	65,658		1,530		(5,876		)	2,661		63,973
Total	$	146,781	$	12,655	$	(5,876	)	$	7,417	$	160,977



(Thousands of Dollars)	Jan. 1, 2015		Purchases		Settlements			Gains Recognized as Regulatory Assets ^(a)		Sept. 30, 2015
Private equity investments	$	101,237	$	24,197	$	—		$	20,261	$	145,695
Real estate	64,249		9,633		(4,341		)	2,435		71,976
Total	$	165,486	$	33,830	$	(4,341	)	$	22,696	$	217,671

(Thousands of Dollars)	Jan. 1, 2014		Purchases		Settlements			Gains Recognized as Regulatory Asset ^(a)		Sept. 30, 2014
Private equity investments	$	62,696	$	22,078	$	—		$	12,230	$	97,004
Real estate	57,368		5,386		(5,876		)	7,095		63,973
Total	$	120,064	$	27,464	$	(5,876	)	$	19,325	$	160,977



	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
Contributions to Diluted Earnings (Loss) Per Share	2015			2014			2015			2014
GAAP earnings (loss) by segment
Regulated electric	$	0.86		$	0.71		$	1.45		$	1.46
Regulated natural gas	(0.01		)	0.01			0.14			0.19
Other ^(a)	0.02			0.03			0.02			0.07
Xcel Energy Inc. and other ^(a)	(0.03		)	(0.02		)	(0.08		)	(0.08		)
Total diluted EPS	$	0.84		$	0.73		$	1.53		$	1.64